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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended March 31, 2005 Commission File No. 0-6694
MEXCO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Colorado 84-0627918
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
214 W. Texas Avenue, Suite 1101 79701
Midland, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (432) 682-1119
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of
the Act:
Title of Each Class Name of Exchange on Which Registered
------------------- ------------------------------------
Common Stock, $0.50 par value American Stock Exchange
Indicate by check-mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve (12) months (or for such shorter period that
the registrant was required to file such reports) and (2) has been subject to
such filing requirements for the past ninety (90) days. Yes |X| No |_|
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (ss.229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or an amendment to this Form 10-K. |_|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes |_| No |X|
As of June 22, 2005, the aggregate market value of the registrant's common
stock held by non-affiliates (using the last price at which a common equity was
sold ($12.30)) was approximately $6,289,765.
The number of shares outstanding of the registrant's common stock as of
June 22, 2005 was 1,733,041.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement relating to the 2005 Annual
Meeting of Shareholders to be held on September 13, 2005, have been incorporated
by reference in Part III of this Form 10-K. Such Proxy Statement will be filed
with the Commission not later than July 30, 2005.
1
TABLE OF CONTENTS
PART I
Item 1. Business 3
Item 2. Properties 9
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of Security Holders 12
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters 13
Item 6. Selected Financial Data 14
Item 6A. Selected Quarterly Financial Data 14
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 15
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 20
Item 8. Financial Statements and Supplementary Data 22
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures 40
Item 9A. Controls and Procedures 40
Item 9B. Other Information 40
PART III
Item 10. Directors and Executive Officers of the Registrant 40
Item 11. Executive Compensation 40
Item 12. Security Ownership of Certain Beneficial Owners and Management 40
Item 13. Certain Relationships and Related Transactions 40
Item 14. Principal Accountant Fees and Services 40
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 41
Signatures 44
2
This Annual Report on Form 10-K contains forward-looking statements that
are based on management's current expectations. Forward-looking statements
include statements regarding our plans, beliefs or current expectations and may
be signified by the words "could", "should", "expect", "project", "estimate",
"believe", "anticipate", "intend", "budget", "plan", "forecast", "predict" and
other similar expressions. Forward-looking statements appear throughout this
Form 10-K with respect to, among other things: profitability; planned capital
expenditures; estimates of oil and gas production; future project dates;
estimates of future oil and gas prices; estimates of oil and gas reserves; our
future financial condition or results of operations; and our business strategy
and other plans and objectives for future operations. Actual results in future
periods may differ materially from those expressed or implied by such
forward-looking statements because of a number of risks and uncertainties
affecting our business, including those discussed in "Item 1 - Business - Risk
Factors" and elsewhere in this report. We disclaim any intention or obligation
to update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
Definitions of terms commonly used in the oil and gas industry and in this
Form 10-K can be found in the Glossary of Terms.
PART I
ITEM 1. BUSINESS
General
Mexco Energy Corporation, a Colorado corporation, is an independent oil
and gas company engaged in the acquisition, exploration and development of oil
and gas properties located in the United States. Unless the context otherwise
requires, references to the "Company", "Mexco", "we", "us" or "our" mean Mexco
Energy Corporation and its consolidated subsidiaries. Incorporated in April 1972
under the name Miller Oil Company, the Company changed its name to Mexco Energy
Corporation effective April 30, 1980. At that time, the shareholders of the
Company also approved amendments to the Articles of Incorporation resulting in a
one-for-fifty reverse stock split of the Company's common stock.
On February 25, 1997, Mexco Energy Corporation acquired all of the issued
and outstanding stock of Forman Energy Corporation, a New York corporation also
engaged in oil and gas exploration and development.
In April 2004, Mexco Energy Corporation formed OBTX, LLC, a Delaware
Limited Liability Company, in which Mexco owns 90% of the stock. The remaining
10% of the stock is split equally among three individuals, one of whom is Arden
Grover, a director of Mexco Energy Corporation. OBTX, LLC is included in the
consolidated financial statements since its date of formation. OBTX, LLC, plans
to participate in any Russian venture entered into and own a 50% interest.
Through March 31, 2005, OBTX, LLC has no operations other than evaluation
activities on properties in Russia.
Our total estimated proved reserves at March 31, 2005 were approximately
7.328 Bcf of natural gas and 151,000 barrels of oil and natural gas liquids, and
our estimated present value of proved reserves was approximately $21 million
based on estimated future net revenues discounted at 10% per annum, pricing and
other assumptions set forth in "Item 2 - Properties" below. During fiscal 2005,
we added proved reserves of 40,000 Mcfe through extensions and discoveries,
acquired .5 Bcfe through acquisitions and had downward revisions of previous
estimates of .47 Bcfe.
Nicholas C. Taylor beneficially owns approximately 51% of the outstanding
shares of our common stock. Mr. Taylor is also our President and Chief Executive
Officer. As a result, Mr. Taylor has significant influence in matters voted on
by our shareholders, including the election of our Board members. Mr. Taylor
participates in all facets of our business and has a significant impact on both
our business strategy and daily operations.
3
Company Profile
Currently we conduct all of our drilling, exploration and production
activities in the United States. All of our oil and gas assets, other than our
investment in GazTex, LLC, are located in the United States, and all of our
revenues are derived from sales to customers within the United States. GazTex,
LLC is owned 50% by OBTX, LLC.
Since our inception, we have been engaged in acquiring and developing oil
and gas properties and the exploration for and production of oil and gas within
the United States. We primarily focus on the exploration for and development of
natural gas resources, as well as increased profit margins through reductions in
operating costs. Our long-term strategy is to increase production and profits,
while increasing concentration on gas reserves. In addition to exploration, we
are also engaged in the business of acquiring proved reserves. Competition for
the purchase of proved reserves is intense. Sellers often utilize a bid process
to sell properties. This process usually intensifies the competition and makes
it extremely difficult for us to acquire reserves without assuming significant
price and production risks. We are actively searching for opportunities to
acquire proved oil and gas properties; however, because the competition is
intense, we cannot give any assurance that we will be successful in our efforts
during fiscal 2006.
While we own oil and gas properties in other states, the majority of our
activities are centered in West Texas. We acquire interests in producing and
non-producing oil and gas leases from landowners and leaseholders in areas
considered favorable for oil and gas exploration, development and production.
For the fiscal year ended March 31, 2005, we acquired 182 acres of leases in
Loving County, Texas for approximately $82,000. In addition, we may acquire oil
and gas interests by joining in oil and gas drilling prospects generated by
third parties. We may also employ a combination of the above methods of
obtaining producing acreage and prospects. In recent years, we have placed
primary emphasis on the evaluation and purchase of producing oil and gas
properties, both working and royalty interests, and re-entry prospects that
could have a potentially meaningful impact on our reserves.
From time to time, we decide to sell certain of our proved properties. In
July 2005, we sold our interest in three wells located in Schleicher County,
Texas, which we also operated in an effort to focus our efforts elsewhere. We
received cash proceeds of approximately $71,000, subject to normal post-closing
adjustments.
Oil and Gas Operations
As of March 31, 2005, gas reserves constituted approximately 89% of the
Company's total proved reserves and approximately 75% of the Company's revenues
for fiscal 2005. Revenues from oil and gas royalty interests accounted for
approximately 22% of the Company's revenues for fiscal 2005.
Viejos Gas Field properties, encompassing 2,583 gross acres, 156 net
acres, 18 gross wells and 1.27 net wells in Pecos County, Texas, account for
approximately 5% of our discounted future net cash flows from proved reserves as
of March 31, 2005, and for fiscal 2005, approximately 14% of revenues and 12% of
production costs.
Gomez Gas Field properties, encompassing 13,847 gross acres, 73 net acres,
24 gross wells and .11 net wells in Pecos County, Texas, account for
approximately 10% of our discounted future net cash flows from proved reserves
as of March 31, 2005, and for fiscal 2005, approximately 12% of revenues and 8%
of production costs.
El Cinco Gas Field properties, encompassing 1,713 gross acres, 1,237 net
acres, 9 gross producing wells and 6.6 net wells in Pecos County, Texas, account
for approximately 41% of our discounted future net cash flows from proved
reserves as of March 31, 2005. This is a multi-pay area where most of the leases
have potential reserves in two zones. Of this amount approximately 24% of our
discounted future net cash flows from proved reserves are attributable to proven
undeveloped reserves which will be developed through re-entry of existing wells
and new drilling. For fiscal 2005, these properties accounted for approximately
18% of revenues and 21% of production costs.
We own interests in and operate 17 producing wells and two shut-in wells.
We own partial interests in an additional 1,982 producing wells located in the
states of Texas, New Mexico, Oklahoma, Louisiana, Arkansas, Wyoming, Kansas,
Colorado, Montana and North Dakota. Additional information concerning these
properties and our oil and gas reserves is provided below.
4
The following table indicates our oil and gas production in each of the
last five years, all of which is located within the United States:
Year Oil(Bbls) Gas (Mcf)
---- --------- ---------
2005................................ 17,372 404,133
2004................................ 20,279 487,564
2003................................ 23,391 538,787
2002................................ 21,139 467,013
2001................................ 18,545 503,773
Competition and Markets
The oil and gas industry is a highly competitive business. Competition for
oil and gas reserve acquisitions is significant. We may compete with major oil
and gas companies, other independent oil and gas companies and individual
producers and operators, some of which have financial and personnel resources
substantially in excess of those available to us. As a result, we may be placed
at a competitive disadvantage. Competitive factors include price, contract terms
and types and quality of service, including pipeline distribution. The price for
oil and gas is widely followed and is generally subject to worldwide market
factors. Our ability to acquire and develop additional properties in the future
will depend upon our ability to conduct operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment in a timely manner.
In addition, the oil and gas industry as a whole also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers. The price and availability of alternative
energy sources could adversely affect our revenue.
Market factors affect the quantities of oil and natural gas production and
the price we can obtain for the production from our oil and natural gas
properties. Such factors include: the extent of domestic production; the level
of imports of foreign oil and natural gas; the general level of market demand on
a regional, national and worldwide basis; domestic and foreign economic
conditions that determine levels of industrial production; political events in
foreign oil-producing regions; and variations in governmental regulations
including environmental, energy conservation and tax laws or the imposition of
new regulatory requirements upon the oil and natural gas industry.
The market for our oil, gas and natural gas liquids production depends on
factors beyond our control including: domestic and foreign political conditions;
the overall level of supply of and demand for oil, gas and natural gas liquids;
the price of imports of oil and gas; weather conditions; the price and
availability of alternative fuels; the proximity and capacity of gas pipelines
and other transportation facilities and overall economic conditions.
Major Customers
We had sales to the following company that amounted to 10% or more of
revenues for the year ended March 31:
2005 2004 2003
---- ---- ----
Sid Richardson Energy Services, Co.
(formerly Koch Midstream Services Company) 21% 29% 28%
Because a ready market exists for oil and gas production, we do not
believe the loss of any individual customer would have a material adverse effect
on our financial position or results of operations.
Risk Factors
There are many factors that affect our business and results of operations,
some of which are beyond our control. The following is a description of some of
the important factors that may cause results of operations in future periods to
differ materially from those currently expected or desired.
5
Oil and gas prices are volatile and could adversely affect our revenues,
cash flow, liquidity and reserve estimates. We cannot predict future oil and
natural gas prices with any certainty. Historically, the markets for oil and gas
have been volatile, and they are likely to continue to be volatile. Factors that
can cause price fluctuations include changes in supply and demand, weather
conditions, the price and availability of alternative fuels, political and
economic conditions in oil producing countries and other factors that are beyond
our control. Natural gas prices affect us more than oil prices because most of
our production and reserves are natural gas.
Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow money or raise additional capital. Lower
prices may also reduce the amount of crude oil and natural gas that can be
produced economically. Changes in oil and gas prices impact both estimated
future net revenue and the estimated quantity of proved reserves. Price
increases may permit additional quantities of reserves to be produced
economically, and price decreases may render uneconomic the production of
reserves previously classified as proved. Thus, we may experience material
increases or decreases in reserve quantities solely as a result of price changes
and not as a result of drilling or well performance.
Lower oil and gas prices increase the risk of ceiling limitation
write-downs. We use the full cost method to account for oil and gas operations.
Accordingly, we capitalize the cost to acquire, explore for and develop crude
oil and natural gas properties. Under the full cost accounting rules, the net
capitalized cost of crude oil and natural gas properties may not exceed a
"ceiling limit" which is based upon the present value of estimated future net
cash flows from proved reserves, discounted at 10% plus the lower of cost or
fair market value of unproved properties. If net capitalized costs of oil and
natural gas properties exceed the ceiling limit, we must charge the amount of
the excess to earnings. This charge does not impact cash flow from operating
activities, but does reduce stockholders' equity and earnings. The risk that we
will be required to write down the carrying value of oil and natural gas
properties increases when oil and natural gas prices are low.
Estimates of proved reserves and the estimated future net revenue from
such reserves are uncertain and inherently imprecise. The process of estimating
oil and gas reserves is complex and requires significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data for each reservoir. The interpretation of such data is a
subjective process dependent upon the quality of the data and the
decision-making and judgment of reservoir engineers.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves,
which may in turn adversely affect our cash flow, results of operations and the
availability of capital resources.
One should not assume that the present value of proved reserves is equal
to the current fair market value of our estimated oil and gas reserves. In
accordance with the requirements of the Securities and Exchange Commission
("SEC"), the estimated discounted future net cash flows from proved reserves are
generally based on prices and costs as of the date of the estimate. Actual
future prices and costs may be materially higher or lower than those as of the
date of the estimate. The timing of both the production and the expenses with
respect to the development and production of oil and gas properties will affect
the timing of future net cash flows from proved reserves and their present
value.
Regulation
Our exploration, development, production and marketing operations are
subject to extensive rules and regulations by federal, state and local
authorities. Numerous federal, state and local departments and agencies have
issued rules and regulations, binding on the oil and gas industry, some of which
carry substantial penalties for noncompliance. State statutes and regulations
require permits for drilling operations, bonds and reports concerning
operations. Most states also have statutes and regulations governing
conservation and safety matters, including the unitization and pooling of oil
and gas properties, the establishment of maximum rates of production from oil
and gas wells and the spacing of such wells. Such statutes and regulations may
limit the rate at which oil and gas otherwise could be produced from our
6
properties. These statutes, along with the regulations interpreting the
statutes, generally are intended to prevent waste of oil and natural gas, and to
protect correlative rights to produce oil and natural gas by assigning allowable
rates of production to each well or proration unit. The regulatory burden on the
oil and gas industry increases its cost of doing business and, consequently,
affects its profitability. Because these rules and regulations are frequently
amended or reinterpreted, we are not able to predict the future cost or impact
of complying with such laws.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions, which affect the
marketing of gas we produce, as well as the revenues we receive for sales of
such production. Since the mid-1980s, the FERC has issued various orders that
have significantly altered the marketing and transportation of gas. These orders
resulted in a fundamental restructuring of interstate pipeline sales and
transportation services, including the unbundling by interstate pipelines of the
sales, transportation, storage and other components of the city-gate sales
services such pipelines previously performed. These FERC actions were designed
to increase competition within all phases of the gas industry. The interstate
regulatory framework may enhance our ability to market and transport our gas,
although it may also subject us to greater competition and to the more
restrictive pipeline imbalance tolerances and greater associated penalties for
violation of such tolerances.
Our sales of oil and natural gas liquids are not presently regulated and
are made at market prices. The price we receive from the sale of those products
is affected by the cost of transporting the products to market. The FERC has
implemented regulations establishing an indexing system for transportation rates
for oil pipelines, which, generally, would index such rate to inflation, subject
to certain conditions and limitations. We are not able to predict with any
certainty what effect, if any, these regulations will have on us. Other factors
being equal, the regulations may, over time, tend to increase transportation
costs which may have the effect of reducing wellhead prices for oil and natural
gas liquids.
Environmental
By nature of our oil and gas operations, we are subject to extensive
federal, state and local environmental laws and regulations controlling the
generation, use, storage and discharge of materials into the environment or
otherwise relating to the protection of the environment. Numerous governmental
departments issue rules and regulations to implement and enforce such laws,
which are often difficult and costly to comply with and which carry substantial
penalties for failure to comply. These laws and regulations may require the
acquisition of a permit before drilling or production commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit construction or drilling activities on certain lands lying
within protected areas, restrict the rate of oil and gas production, require
remedial actions to prevent pollution from former operations and impose
substantial liabilities for pollution resulting from our operations. In
addition, these laws and regulations may impose substantial liabilities and
penalties for failure to comply with them or for any contamination resulting
from our operations. We believe we are in compliance, in all material respects,
with applicable environmental requirements. We do not believe costs relating to
these laws and regulations have had a material adverse effect on our operations
or financial condition in the past. As these laws and regulations become more
stringent and complex, there is no assurance that changes in or additions to
laws or regulations regarding the protection of the environment will not have
such an impact in the future.
The United States Oil Pollution Act of 1990 ("OPA `90"), and similar
legislation enacted in Texas, Louisiana and other coastal states, addresses oil
spill prevention and control and significantly expands liability exposure across
all segments of the oil and gas industry. OPA `90 and such similar legislation
and related regulations impose on us a variety of obligations related to the
prevention of oil spills and liability for damages resulting from such spills.
OPA `90 imposes strict and, with limited exceptions, joint and several
liabilities upon each responsible party for oil removal costs and a variety of
public and private damages.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or the site where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances at the site
where the release occurred. Under CERCLA, such persons may be subject to joint
7
and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. We are able to control
directly the operation of only those wells with respect to which we act as
operator. Notwithstanding our lack of direct control over wells operated by
others, the failure of an operator other than us to comply with applicable
environmental regulations may, in certain circumstances, be attributed to us. We
do not believe that we will be required to incur any material capital
expenditures to comply with existing environmental requirements.
The Resource Conservation and Recovery Act ("RCRA") and analogous state
laws govern the handling and disposal of hazardous and solid wastes. Wastes that
are classified as hazardous under RCRA are subject to stringent handling,
recordkeeping, disposal and reporting requirements. RCRA specifically excludes
from the definition of hazardous waste "drilling fluids, produced waters, and
other wastes associated with the exploration, development, or production of
crude oil, natural gas or geothermal energy." However, these wastes may be
regulated by the EPA or state agencies as solid waste. Moreover, many ordinary
industrial wastes, such as paint wastes, waste solvents, laboratory wastes and
waste compressor oils, are regulated as hazardous wastes. Although the costs of
managing hazardous waste may be significant, we do not expect to experience more
burdensome costs than similarly situated companies.
State water discharge regulations and federal waste discharge permitting
requirements adopted pursuant to the Federal Water Pollution Control Act
prohibit, or are expected in the future to prohibit, the discharge of produced
water and sand and other substances related to the oil and gas industry into
coastal waters. Although the costs to comply with such mandates under state or
federal law may be significant, the entire industry will experience similar
costs, and we do not believe that these costs will have a material adverse
impact on our financial condition and operations.
Insurance
Our operations are subject to all the risks inherent in the exploration
for, and development and production of oil and gas including blowouts, fires and
other casualties. We maintain insurance coverage customary for operations of a
similar nature, but losses could arise from uninsured risks or in amounts in
excess of existing insurance coverage.
Employees
As of March 31, 2005, we had two full-time and three part-time employees.
We believe that relations with these employees are generally satisfactory. Our
employees are not covered by collective bargaining arrangements. From time to
time, we utilize the services of independent contractors to perform various
field and other services. Experienced personnel are available in all disciplines
should the need to hire additional staff arise.
Office Facilities
We maintain our principal offices at 214 W. Texas, Suite 1101, Midland,
Texas pursuant to a month to month lease.
Title to Properties
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time properties believed to be suitable for
drilling operations are acquired by us. Prior to the commencement of drilling
operations, a thorough title examination of the drill site tract is conducted
and curative work is performed with respect to significant defects, if any,
before proceeding with operations. A thorough title examination has been
performed with respect to substantially all leasehold producing properties
currently owned by us. We believe the title to our leasehold properties is good
and defensible in accordance with standards generally acceptable in the oil and
gas industry subject to such exceptions that, in the opinion of counsel employed
in the various areas in which we have conducted exploration activities, are not
so material as to detract substantially from the use of such properties.
8
The leasehold properties we own are subject to royalty, overriding royalty
and other outstanding interests customary in the industry. The properties may be
subject to burdens such as liens incident to operating agreements and current
taxes, development obligations under oil and gas leases and other encumbrances,
easements and restrictions. We do not believe any of these burdens will
materially interfere with its use of these properties
Substantially all of our properties are currently mortgaged under a deed
of trust to secure funding through a revolving line of credit.
Mexco Energy Corporation files quarterly, yearly and other reports with
the SEC. You may obtain a copy of any materials filed by Mexco Energy
Corporation with the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549 or by
calling 1-800-SEC-0300. The SEC also maintains an Internet site that contains
reports, proxy and information statements and other information regarding
issuers that file electronically with the SEC at http://www.sec.gov. Mexco
Energy Corporation also employs the Public Register's Annual Report Service
which can provide you a copy of our annual report at http://www.prars.com, free
of charge, as soon as practicable after providing such report to the SEC. We
currently do not maintain an internet website.
ITEM 2. PROPERTIES
Oil and Natural Gas Reserves
Estimates of our proved oil and gas reserves, which are located entirely
within the United States, were prepared in accordance with the guidelines
established by the SEC and Financial Accounting Standards Board. The estimates
as of March 31, 2005, 2004 and 2003 are based on evaluations prepared by Joe C.
Neal and Associates, Petroleum Consultants. For information concerning our costs
incurred for oil and gas operations, net revenues from oil and gas production,
estimated future net revenues attributable to our oil and gas reserves, present
value of future net revenues discounted at 10% and changes therein, see Notes to
the Company's consolidated financial statements.
We emphasize that reserve estimates are inherently imprecise and there can
be no assurance that the reserves set forth below will be ultimately realized.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will most likely vary from the assumptions and estimates. Any
significant variance could materially affect the estimated quantities and value
of our oil and gas reserves, which in turn may adversely affect our cash flow,
results of operations and the availability of capital resources.
In accordance with applicable financial accounting and reporting standards
of the SEC, the estimates of our proved reserves and the present value of proved
reserves set forth herein are made using oil and gas sales prices estimated to
be in effect as of the date of such reserve estimates and are held constant
throughout the life of the properties. Actual future prices and costs may be
materially higher or lower than those as of the date of the estimate. The timing
of both the production and the expenses with respect to the development and
production of oil and gas properties will affect the timing of future net cash
flows from proved reserves and their present value.
We have not filed any other oil or gas reserve estimates or included any
such estimates in reports to other federal or foreign governmental authority or
agency within the last twelve months.
Our estimated proved oil and gas reserves and present value of estimated
future net revenues from proved oil and gas reserves in the periods ended March
31 are summarized below.
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PROVED RESERVES
March 31,
---------------------------------------------
2005 2004 2003
----------- ----------- -----------
Oil (Bbls):
Proved developed - Producing 106,495 75,455 93,199
Proved developed - Non-producing 1,388 1,386 1,386
Proved undeveloped 42,719 55,613 55,564
----------- ----------- -----------
Total 150,602 132,454 150,149
=========== =========== ===========
Natural gas (Mcf):
Proved developed - Producing 3,535,316 3,207,186 3,451,880
Proved developed - Non-producing 1,061,190 1,067,010 1,065,902
Proved undeveloped 2,731,013 3,643,116 3,413,846
----------- ----------- -----------
Total 7,327,519 7,917,312 7,931,628
=========== =========== ===========
Present value of estimated future
net revenues before income taxes $20,946,720 $19,127,440 $20,772,830
=========== =========== ===========
The preceding tables should be read in connection with the following
definitions:
Proved Reserves. Estimated quantities of oil and gas, based on geologic
and engineering data, appear with reasonable certainty to be economically
recoverable in future years from known reservoirs under existing economic
and operating conditions.
Proved Developed Reserves. Proved oil and gas reserves expected to be
recovered through existing wells with existing equipment and operating
methods. Developed reserves include both producing and non-producing
reserves. Producing reserves are those reserves expected to be recovered
from existing completion intervals producing as of the date of the reserve
report. Non-producing reserves are currently shut-in awaiting a pipeline
connection or in reservoirs behind the casing or at minor depths above or
below the producing zone and are considered recoverable by production
either from wells in the field, by successful drill-stem tests, or by core
analysis. Non-producing reserves require only moderate expense for
recovery.
Proved Undeveloped Reserves. Proved oil and gas reserves expected to be
recovered from additional wells yet to be drilled or from existing wells
where a relatively major expenditure is required for completion.
Productive Wells and Acreage
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. Wells that are
completed in more than one producing zone are counted as one well. The following
table indicates our productive wells as of March 31, 2005:
Gross Net
----- ---
Oil .................................. 1,287 14
Gas .................................. 712 11
----- -----
Total Productive Wells .......... 1,999 25
===== =====
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional interests
owned in gross acres. As of March 31, 2005, we own approximately 7,796 gross and
3,610 net acres of material undeveloped acreage located in Texas and North
Dakota.
10
The following table sets forth the approximate developed acreage in which
we held a leasehold mineral or other interest at March 31, 2005.
Developed Acres
--------------------------
Gross Net
------- -------
Texas ........................ 140,406 5,115
New Mexico ................... 19,877 147
North Dakota ................. 27,079 26
Louisiana .................... 32,947 37
Oklahoma ..................... 41,162 185
Montana ...................... 9,788 5
Kansas ....................... 7,880 21
Wyoming ...................... 3,298 4
Colorado ..................... 1,200 1
Arkansas ..................... 320 --
------- -------
Total ........................ 283,957 5,541
======= =======
Drilling Activities
The following table sets forth our drilling activity for the years ended
March 31, 2005, 2004 and 2003:
Year Ended March 31,
----------------------------------------------------------
2005 2004 2003
---------------- ---------------- ----------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Exploratory Wells
Productive 2 .01 9 .03 2 .01
Nonproductive -- -- 2 .30 1 .07
------ ------ ------ ------ ------ ------
Total 2 .01 11 .33 3 .08
====== ====== ====== ====== ====== ======
Development Wells
Productive 10 .05 12 .02 10 .17
Nonproductive -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Total 10 .05 12 .02 10 .17
====== ====== ====== ====== ====== ======
The information contained in the foregoing table should not be considered
indicative of future drilling performance, nor should it be assumed that there
is any necessary correlation between the number of productive wells drilled and
the amount of oil and gas that may ultimately be recovered by us.
Net Production, Unit Prices and Costs
The following table summarizes the net oil and natural gas production for
the Company, the average sales price per barrel of oil and per thousand cubic
feet ("mcf") of natural gas produced and the average production (lifting) cost
per unit of production for the years ended March 31, 2005, 2004 and 2003.
Year Ended March 31,
--------------------------------------------
2005 2004 2003
------------ ------------ ------------
Oil (a):
Production (Bbls) 17,372 20,279 23,391
Revenue $ 727,822 $ 588,089 $ 640,685
Average Bbls per day 48 56 64
Average sales price per Bbl $ 41.90 $ 29.00 $ 27.39
Gas (b):
Production (Mcf) 404,133 487,564 538,787
Revenue $ 2,236,067 $ 2,321,864 $ 2,041,074
Average Mcf per day 1,107 1,336 1,476
Average sales price per Mcf $ 5.53 $ 4.76 $ 3.79
Production cost:
Production cost $ 780,233 $ 942,093 $ 848,513
Equivalent Mcf (c) 508,365 609,232 679,133
Production cost per equivalent Mcf $ 1.53 $ 1.55 $ 1.25
Production cost per sales dollar $ 0.26 $ 0.32 $ 0.32
Total oil and gas revenues $ 2,963,889 $ 2,909,953 $ 2,681,759
11
(a) Includes condensate.
(b) Includes natural gas products.
(c) Oil production is converted to equivalent mcf at the rate of 6 mcf per
barrel ("bbl"), representing the estimated relative energy content of
natural gas to oil.
ITEM 3. LEGAL PROCEEDINGS
We are a defendant in a lawsuit that has arisen in the ordinary course of
business related to the oil and gas leases on the Campbell 15-1 well in Hemphill
County, Texas. While the outcome of this lawsuit cannot be predicted with
certainty, management does not expect this lawsuit to have a material adverse
effect on our consolidated financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter ended March 31, 2005.
Executive Officers of the Registrant
The following table sets forth certain information concerning the
executive officers of the Company as of March 31, 2005.
Name Age Position
---- --- --------
Nicholas C. Taylor 67 President and Chief Executive Officer
Donna Gail Yanko 60 Vice President and Corporate Secretary
Tamala L. McComic 36 Vice President, Treasurer, and Asst Secretary
Set forth below is a description of the backgrounds of each executive
officer of the Company, including employment history for at least the last five
years.
Nicholas C. Taylor was elected President, Treasurer and Director of the
Company in April 1983 and continues to serve as President and Director on a part
time basis, as required. Mr. Taylor served as Treasurer until March 1999. From
July 1993 to the present, Mr. Taylor has been involved in the independent
practice of law and other business activities. For more than the prior 19 years,
he was a director and shareholder of the law firm of Stubbeman, McRae, Sealy,
Laughlin & Browder, Inc., Midland, Texas, and a partner of the predecessor firm.
In 1995 he was appointed by the Governor of Texas to the State Securities Board
through January 2001. In addition to serving as chairman for four years, he
continued to serve as a member until 2004.
Donna Gail Yanko worked as part-time administrative assistant to the Chief
Executive Officer and as Assistant Secretary of the Company until June 1992 when
she was appointed Corporate Secretary. Mrs. Yanko was appointed to the position
of Vice President and elected to the board of directors of the Company in 1990.
Tamala L. McComic became Controller for the Company in July 2001. She was
appointed Assistant Secretary of the Company in August 2001 and Treasurer in
September 2001. From 1994 to 2001 Mrs. McComic was Regional Controller and
Credit Manager for Transit Mix Concrete & Materials Company, a subsidiary of
Trinity Industries, Inc. In May 2003, Mrs. McComic was appointed Vice President,
Chief Financial Officer and continues to serve as Treasurer and Assistant
Secretary.
12
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
In September 2003, our common stock began trading on the American Stock
Exchange under the symbol "MXC". Prior to September 2003, the Company's common
stock was traded on the over-the-counter market bulletin board under the symbol
"MEXC". The registrar and transfer agent is Computershare Trust Company, Inc.,
P.O. Box 1596, Denver, Colorado, 80201 (Tel: 303-262-0600). As of March 31,
2005, the Company had approximately 1,385 shareholders of record and 1,766,566
shares issued.
PRICE RANGE OF COMMON STOCK
High Low
------ ------
2005:
April - June 2004 (2) $ 7.85 $ 6.80
July - September 2004(2) 6.80 6.00
October - December 2004 (2) 6.15 5.55
January - March 2005 (2) 12.90 5.65
2004:
April - June 2003 (1) $ 7.75 $ 4.00
July - September 5, 2003 (1) 7.00 6.50
September 5 - 30, 2003 (2) 7.90 7.50
October - December 2003 (2) 8.50 7.85
January - March 2004 (2) 8.50 7.55
- ----------
(1) Reflects high and low bid information received from Pink Sheets LLC,
formerly National Quotation Bureau, LLC. These bid quotations represent
prices between dealers, without retail markup, markdown or commissions,
and do not reflect actual transactions.
(2) Reflects the high and low sales prices for the Company's Common Stock, as
reported on the American Stock Exchange.
On June 22, 2005, the closing price was $12.30.
Dividends
On February 1, 2002 our board of directors declared a stock dividend
consisting of shares of par value $0.50 common stock of the Company in the
amount of ten percent (10%) of the outstanding shares, or 1 share for each 10
shares held by all stockholders of record of Mexco Energy Corporation as of
February 15, 2002, with any resulting fractional share dividends to be rounded
up or down to the nearest whole number of shares and issued the stock dividend
accordingly. The payable date for this dividend was February 28, 2002 and
resulted in an additional 160,566 shares of stock issued and outstanding.
We have never declared or paid any cash dividends on our common stock. We
currently intend to retain future earnings and other cash resources, if any, for
the operation and development of our business and do not anticipate paying any
cash dividends on our common stock in the foreseeable future. Payment of any
future dividends will be at the discretion of our board of directors after
taking into account many factors, including our financial condition, operating
results, current and anticipated cash needs and plans for expansion. In
addition, our current bank loan prohibits us from paying cash dividends on our
common stock. Any future dividends may also be restricted by any loan agreements
which we may enter into from time to time.
13
ITEM 6. SELECTED FINANCIAL DATA
Year Ended March 31,
-----------------------------------------------------------------------------------
2005 2004 2003 2002 2001
-----------------------------------------------------------------------------------
Statement of Operations:
Operating revenues $ 2,969,826 $ 2,915,355 $ 2,949,113 $ 1,778,583 $ 3,099,966
Operating income 924,230 785,739 926,277 252,101 1,881,776
Other income (expense) (88,408) (82,766) (95,357) (54,706) (92,160)
Net income $ 577,527 $ 429,846 $ 672,808 $ 189,291 $ 1,539,458
Net income per
share - basic (1)(2) $ 0.33 $ 0.25 $ 0.39 $ 0.11 $ 0.86
Net income per
share - diluted (1)(2) $ 0.32 $ 0.24 $ 0.39 $ 0.11 $ 0.86
Weighted average shares
outstanding - basic (1) 1,734,726 1,736,047 1,741,462 1,768,314 1,784,825
Weighted average shares
outstanding - diluted (1) 1,801,167 1,802,300 1,746,831 1,768,579 1,787,503
Balance Sheet:
Property and equipment, net $ 8,484,743 $ 7,647,284 $ 7,028,659 $ 5,895,429 $ 4,009,852
Total assets 9,303,149 8,172,464 7,688,638 6,347,965 4,961,360
Total debt 1,990,000 1,700,000 2,150,000 1,710,000 600,000
Stockholders' equity 6,038,195 5,435,219 4,956,388 4,276,042 4,046,452
Cash Flow:
Cash provided by operations $ 1,451,628 $ 1,517,479 $ 1,369,690 $ 899,977 $ 1,903,345
(1) Amounts have been adjusted to reflect the 10% stock dividend effected on
February 1, 2002.
(2) Year 2004 includes a cumulative effect of change in accounting principle
(Cumulative Effect) loss of $0.06 related to the adoption of Statement of
Financial Accounting Standards (SFAS) No. 143, Asset Retirement
Obligations.
ITEM 6A. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
FISCAL 2005
--------------------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
-------- -------- -------- --------
Net sales $791,476 $774,966 $722,452 $674,995
Operating profit 250,596 287,220 225,160 161,254
Net income 172,406 183,359 119,060 102,702
Net income per share-basic 0.09 0.11 0.07 0.06
Net income per share-diluted 0.09 0.10 0.07 0.06
FISCAL 2004
--------------------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
-------- -------- -------- --------
Net sales $723,258 $650,783 $768,852 $767,060
Operating profit 254,264 123,570 196,292 211,613
Net income before cumulative effect 204,628 57,255 118,470 151,760
Net income per share-basic (1) 0.12 0.03 0.07 0.03
Net income per share-diluted (1) 0.12 0.03 0.06 0.03
(1) First quarter of fiscal 2004 includes a cumulative effect of change in
accounting principle (Cumulative Effect) loss of $0.06 related to the
adoption of Statement of Financial Accounting Standards (SFAS) No. 143,
Asset Retirement Obligations.
14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to provide information relevant to an
understanding of our financial condition, changes in our financial condition and
our results of operations and cash flows and should be read in conjunction with
our consolidated financial statements and notes thereto included elsewhere in
this Form 10-K.
Liquidity and Capital Resources and Commitments
Historically, we have funded our operations, acquisitions, exploration and
development expenditures from cash generated by operating activities, bank
borrowings and issuance of common stock. Our primary financial resource is our
base of oil and gas reserves. We pledge our producing oil and gas properties to
secure our revolving line of credit.
In fiscal 2005, we primarily used cash provided by operations ($1,451,628)
and borrowings on the line of credit ($950,000) to fund oil and gas property
acquisitions and development ($1,568,810). We had working capital of $376,478 as
of March 31, 2005 compared to a working capital deficit of $15,506 as of March
31, 2004, mainly as a result of the change in maturity date of our revolving
line of credit.
In fiscal 2003, the board of directors authorized the use of up to
$250,000 to repurchase shares of our common stock. During fiscal year 2003, we
repurchased 30,244 shares, at an aggregate cost of $127,536 for the treasury
account. As part of this ongoing repurchase plan, we repurchased 281 shares
during fiscal 2004 at an aggregate cost of $1,389. During fiscal year 2005, we
repurchased 3,000 shares at an aggregate cost of $16,650 for the treasury
account.
In December 2002, we entered into a participation agreement with Falcon
Bay Exploration, LLC exercising its right to purchase at an aggregate cash price
of $597,301, the acreage and seismic data on the first of four such prospects
referred to in the exploration agreement with Falcon Bay Exploration, LLC. This
information is contained in the Form 8-K we filed on December 6, 2002. The
warrants issued related to this transaction expired, unexercised, on December 5,
2004. We continue to hold 1,280 undeveloped acres in the East Umbrella Point
Prospect in Trinity Bay, Chambers County, Texas and are actively pursuing
partners to participate in this project and plan to drill a well prior to March
31, 2006. No further prospects will be generated under this exploration
agreement.
During fiscal year 2004, the Company purchased a one-quarter interest in
leases and/or options on leases in Stark County, North Dakota covering 4,920
gross acres for approximately $107,000. A director and employee of Mexco Energy
Corporation, will receive a 1.5% ORRI on any wells drilled on this acreage.
During fiscal year 2005, we elected to exercise options on approximately 320
acres in Stark County, North Dakota, therefore allowing the additional options
to expire or be reassigned.
During fiscal year 2004, the Company purchased partially developed royalty
interests in Jackson Parish, Louisiana for approximately $80,000. These
properties are operated by Anadarko Petroleum Corporation in the Lower Cotton
Valley formation.
In March 2004, we purchased additional partially developed royalty
interests in Jackson Parish, Louisiana and interests in Limestone County, Texas
for approximately $224,000. The properties in Limestone County, operated by XTO
Energy, Inc., are in the Cotton Valley formation and contain 23 producing wells
and an additional six permitted and/or drilling wells. This acreage contains
approximately 100 potential undrilled locations on 40 acre spacing. The property
in Louisiana is operated by Anadarko and produces from the Lower Cotton Valley
formation. These royalty purchases advanced the Company's primary goal of
acquiring natural gas reserves.
In March 2004, we signed an agreement in Moscow, Russia to begin a
preliminary geological and engineering study for exploration and development of
natural gas reserves in Russia. A team of U.S. and Russia experts commenced a
study of a number of undeveloped oil and gas properties. Mexco Energy
Corporation has set up OBTX, LLC, a Delaware limited liability company, in which
Mexco owns a 90% interest with the remaining 10% interest split equally among
three individuals, one of whom is Arden Grover, a director of Mexco Energy
Corporation. OBTX, LLC plans to participate in any Russian ventures entered
into and own a 50% interest.
15
Through March 31, 2005, we have reviewed a number of possible projects in
Russia. We established a long-term investment in GazTex, LLC for our capital
costs of these projects of $282,126. Any projects reviewed that we have decided
not to continue studying or develop have been expensed. We expensed
approximately $83,000 related to Russian projects in fiscal 2005.
In August 2004, we purchased partially developed royalty interests in four
producing gas units in Freestone County, Texas with approximately 33 producing
wells for approximately $500,000. This acreage contains approximately 17
potential undeveloped locations, which are principally Cotton Valley infill
wells.
In February 2005, we purchased a mineral interest in Devon's Aycock Gas
Unit containing 160 acres for approximately $56,000. The unit currently has one
producing well with plans to drill two additional wells in 2006. This unit is
located in Freestone County, Texas where the company has purchased other royalty
interests.
Effective February 2005, we purchased for $550,000 partially developed
royalty interests primarily located in Freestone and Limestone Counties, Texas
and operated by Anadarko Petroleum, XTO, and Devon Energy. These properties
contain 75 producing wells and an additional nine permitted and/or drilling
wells in the Cotton Valley formation. This acreage contains approximately 83
potential undeveloped locations, which are principally Cotton Valley infill
wells.
We continue to focus our efforts on the acquisition of royalties in areas
with significant development potential.
We are reviewing several other projects in which we may participate. The
cost of such projects would be funded, to the extent possible, from existing
cash balances and cash flow from operations. The remainder may be funded through
borrowings on the credit facility. See Note 3 of Notes to Consolidated Financial
Statements for a description of our revolving credit agreement with Bank of
America, N.A.
Crude oil and natural gas prices have fluctuated significantly in recent
years as well as in recent months. Fluctuations in price have a significant
impact on our financial condition and liquidity. However, management believes we
can maintain adequate liquidity for the next fiscal year.
Results of Operations
Fiscal 2005 Compared to Fiscal 2004
Oil and gas sales increased from $2,909,953 in 2004 to $2,963,889 in 2005,
an increase of $53,936 or 2%. This increase was attributable to an increase in
oil and gas prices during the year. The average oil price increased from $29.00
per bbl in 2004 to $41.90 per bbl in 2005, an increase of $12.90 per bbl or 44%.
The average gas price increased from $4.76 in 2004 to $5.53 per mcf in 2005, an
increase of $.77 per mcf or 16%. Oil production decreased from 20,279 bbls in
2004 to 17,372 bbls in 2005, a decrease of 2,907 bbls or 14%. Gas production
decreased from 487,564 mcf in 2004 to 404,133 mcf in 2005, a decrease of 83,431
mcf or 17%. Such decreases primarily were due to normal decline in production.
Production costs decreased from $942,093 in 2004 to $780,233 in 2005, a
decrease of $161,860 or 17%. This is primarily attributable to a decreased
number of repairs on operated properties during the year and a decrease in
production units.
Depreciation, depletion and amortization decreased from $633,443 in 2004
to $582,268 in 2005, a decrease of $51,175 or 8%, due primarily to a decrease in
production. There was no impairment of oil and gas properties in fiscal 2004 or
2005.
General and administrative expenses increased from $529,834 in 2004 to
$658,360 in 2005, an increase of $128,526 or 24%. This increase was primarily
attributable to costs associated with the Russian venture. Organization costs
directly related to forming OBTX, LLC was $46,514. There was also an increase in
contract and consulting services that were directly related to Russian projects
that we decided to discontinue totaling approximately $83,000.
16
Interest expense increased from $83,530 in 2004 to $89,154 in 2005, an
increase of $5,624 or 7%. This increase was attributable to increased borrowings
and increased interest rates during the current fiscal year.
Income tax expense increased from $170,860 in 2004 to $272,609 in 2005, an
increase of $101,749 or 60%. This increase was attributable to the utilization
of part of the statutory depletion carryforward in fiscal 2005 due to increased
pre-tax income.
Fiscal 2004 Compared to Fiscal 2003
Oil and gas sales increased from $2,681,759 in 2003 to $2,909,953 in 2004,
an increase of $228,194 or 9%. This increase was attributable to an increase in
oil and gas prices during the year. The average oil price increased from $27.39
per bbl in 2003 to $29.00 per bbl in 2004, an increase of $1.61 per bbl or 6%.
The average gas price increased from $3.79 in 2003 to $4.76 per mcf in 2004, an
increase of $.97 per mcf or 26%. Oil production decreased from 23,391 bbls in
2003 to 20,279 bbls in 2004, a decrease of 3,112 bbls or 13%. Gas production
decreased from 538,787 mcf in 2003 to 487,564 mcf in 2004, a decrease of 51,223
mcf or 10%. Such decreases primarily were due to normal decline in production.
Other income decreased from $267,354 in 2003 to $5,402 in 2004, a decrease
of $261,952. This decrease is the result of the proceeds received ($254,862)
from the settlement of a class action lawsuit against a gas purchaser involving
contract price disputes in fiscal 2003.
Production costs increased from $848,513 in 2003 to $942,093 in 2004, an
increase of $93,580 or 11%. This is primarily attributable to an increased
number of repairs on operated properties during the year.
Depreciation, depletion and amortization decreased from $641,827 in 2003
to $633,443 in 2004, a decrease of $8,384 or 1%, due primarily to a decrease in
production. There was no impairment of oil and gas properties in fiscal 2003 or
2004.
General and administrative expenses decreased from $532,496 in 2003 to
$529,834 in 2004, a decrease of $2,662 or 0.5%. This decrease was primarily
attributable to the decreased cost of consulting expenses during the year.
Interest expense decreased from $96,337 in 2003 to $83,530 in 2004, a
decrease of $12,807 or 13%. This decrease was attributable to decreased
borrowings during the current fiscal year.
Alternative Capital Resources
Although we have primarily used cash from operating activities and funding
from the line of credit as our primary capital resources, we have in the past,
and could in the future, use alternative capital resources. These could include
the sale of assets and/or issuances of common stock through a public offering.
We could also obtain funds through a private placement.
Contractual Obligations
We have no off-balance sheet debt or unrecorded obligations and have not
guaranteed the debt of any other party. The following table summarizes our
future payments we are obligated to make based on agreements in place as of
March 31, 2005:
Payments Due In:
---------------------------------------------------------
Total 1 year 1-3 years 3 years
---------- ---------- ---------- ----------
Contractual obligations:
Secured bank line of credit $1,990,000 $ -- $1,990,000 $ --
These amounts represent the balances outstanding under the bank line of
credit. These repayments assume that interest will be paid on a monthly basis
and that no additional funds will be drawn.
17
Other Matters
Critical Accounting Policies and Estimates
In preparing financial statements, management makes informed judgments and
estimates that affect the reported amounts of assets and liabilities as of the
date of the financial statements and affect the reported amounts of revenues and
expenses during the reporting period. On an ongoing basis, management reviews
its estimates, including those related to litigation, environmental liabilities,
income taxes, fair value and determination of proved reserves. Changes in facts
and circumstances may result in revised estimates and actual results may differ
from these estimates.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude Oil and Natural Gas Activities.
SEC Regulation S-X defines the financial accounting and reporting standards for
companies engaged in crude oil and natural gas activities. Two methods are
prescribed: the successful efforts method and the full cost method. We have
chosen to follow the full cost method under which all costs associated with
property acquisition, exploration and development are capitalized. We also
capitalize internal costs that can be directly identified with acquisition,
exploration and development activities and do not include any costs related to
production, general corporate overhead or similar activities. Effective with the
adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties
also includes estimated asset retirement costs recorded based on the fair value
of the asset retirement obligation when incurred. Gain or loss on the sale or
other disposition of oil and gas properties is not recognized, unless the gain
or loss would significantly alter the relationship between capitalized costs and
proved reserves of oil and natural gas attributable to a country. Under the
successful efforts method, geological and geophysical costs and costs of
carrying and retaining undeveloped properties are charged to expense as
incurred. Costs of drilling exploratory wells that do not result in proved
reserves are charged to expense. Depreciation, depletion, amortization and
impairment of crude oil and natural gas properties are generally calculated on a
well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of crude oil and
natural gas properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher depreciation, depletion and amortization rate on our
crude oil and natural gas properties.
At the time it was adopted, management believed that the full cost method
would be preferable, as earnings tend to be less volatile than under the
successful efforts method. However, the full cost method makes us more
susceptible to significant non-cash charges during times of volatile commodity
prices because the full cost pool may be impaired when prices are low. These
charges are not recoverable when prices return to higher levels. Our crude oil
and natural gas reserves have a relatively long life. However, temporary drops
in commodity prices can have a material impact on our business including impact
from the full cost method of accounting.
Ceiling Test. Companies that use the full cost method of accounting for
oil and gas exploration and development activities are required to perform a
ceiling test each quarter. The full cost ceiling test is an impairment test
prescribed by SEC Regulation S-X Rule 4-10. The test determines a limit, or
ceiling, on the book value of oil and gas properties. That limit is basically
the after tax present value of the future net cash flows from proved crude oil
and natural gas reserves, excluding future cash outflows associated with
settling asset retirement obligations that have been accrued on the balance
sheet, plus the lower of cost or fair market value of unproved properties. If
net capitalized costs of crude oil and natural gas properties exceed the ceiling
limit, we must charge the amount of the excess to earnings. This is called a
"ceiling limitation write-down." This charge does not impact cash flow from
operating activities, but does reduce our stockholders' equity and reported
earnings. The risk that we will be required to write down the carrying value of
crude oil and natural gas properties increases when crude oil and natural gas
prices are depressed or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves or
if purchasers cancel long-term contracts for natural gas production. An expense
recorded in one period may not be reversed in a subsequent period even though
higher crude oil and natural gas prices may have increased the ceiling
applicable to the subsequent period.
18
Estimates of our proved reserves included in this report are prepared in
accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a
function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o and the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was based on
evaluations prepared by independent petroleum engineers. Estimates prepared by
other third parties may be higher or lower than those included herein. Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from the
quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
It should not be assumed that the present value of future net cash flows
is the current market value of our estimated proved reserves. In accordance with
SEC requirements, we base the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A expense
will increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher cost
fields.
Use of Estimates. In preparing financial statements in conformity with
accounting principles generally accepted in the United States of America,
management is required to make informed judgments and estimates that affect the
reported amounts of assets and liabilities as of the date of the financial
statements and affect the reported amounts of revenues and expenses during the
reporting period. Although management believes its estimates and assumptions are
reasonable, actual results may differ materially from those estimates.
Significant estimates affecting these financial statements include the estimated
quantities of proved oil and gas reserves, the related present value of
estimated future net cash flows and the future development, dismantlement and
abandonment costs.
Revenue Recognition. We recognize crude oil and natural gas revenue from
our interest in producing wells as crude oil and natural gas is sold from those
wells, net of royalties. We utilize the sales method to account for gas
production volume imbalances. Under this method, income is recorded based on our
net revenue interest in production taken for delivery. We had no material gas
imbalances.
Excluded Costs. Oil and gas properties include costs that are excluded
from capitalized costs being amortized. These amounts represent investments in
unproved properties and major development projects. These costs are excluded
until proved reserves are found or until it is determined that the costs are
impaired. All costs excluded are reviewed at least quarterly to determine if
impairment has occurred. The amount of any impairment is transferred to the
capitalized costs being amortized (the DD&A pool) or a charge is made against
earnings for those international operations where a reserve base has not yet
been established. Impairments transferred to the DD&A pool increase the DD&A
rate. Costs excluded for oil and gas properties are generally classified and
evaluated as significant or individually insignificant properties.
Asset Retirement Obligations. The estimated costs of restoration and
removal of facilities are accrued. The fair value of a liability for an asset's
retirement obligation is recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated by
19
by the units of production method. If the liability is settled for an amount
other than the recorded amount, a gain or loss is recognized. For all periods
presented, we have included estimated future costs of abandonment and
dismantlement in the full cost amortization base and amortize these costs as a
component of our depletion expense.
Long Term Investment in GazTex, LLC. The Company accounts for its
investment in a limited liability company on the equity basis and adjusts the
investment balance to agree with its equity in the underlying assets of the
entity.
Recent Accounting Pronouncements
FASB Staff Position (FSP) FAS 109-1, "Application of FASB Statement No.
109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production
Activities Provided by the American Jobs Creation Act of 2004," provides
guidance on the application of SFAS No. 109, "Accounting for Income Taxes," to
the tax deduction on qualified production as provided for in the American Jobs
Creation Act of 2004 (Jobs Act). FSP FAS 109-1 provides that the deduction
should be treated as a special deduction under paragraph 231 of SFAS No. 109.
This deduction takes effect beginning in 2005 and therefore, has no impact on
the current year financial statements. We are currently assessing the effect of
FAS 109-1 on the fiscal 2006 financial statements.
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 123 (revised 2004) "Share-Based Payments" ("SFAS 123R"). SFAS 123R
requires that the cost from all share-based payment transactions, including
stock options, be recognized in the financial statements at fair value. We
currently use the intrinsic-value method to account for these share-based
payments. For public companies, SFAS 123R is effective for fiscal years
beginning after June 15, 2005. We will adopt the provisions of this statement in
the first quarter of fiscal 2007 and are currently assessing the effect of SFAS
123R on the financial statements.
The SEC issued Staff Accounting Bulletin (SAB) No. 106 regarding the
application of Statement of Financial Accounting Standards (SFAS) No. 143,
"Accounting for Asset Retirement Obligations," by oil and gas producing entities
that follow the full cost accounting method. SAB No. 106, which was adopted in
the third quarter of fiscal 2005, states that after adoption of SFAS No. 143,
the future cash outflows associated with settling asset retirement obligations
that have been accrued on the balance sheet should be excluded from the present
value of estimated future net cash flows used for the full cost ceiling test
calculation. It also states that estimated dismantlement and abandonment costs
in future development activities be included in the calculation of depreciation,
depletion and amortization. The adoption of SAB No. 106 did not have any
material impact on our financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Factors
All of the Company's financial instruments are for purposes other than
trading. At March 31, 2005, the Company had not entered into any hedge
arrangements, commodity swap agreements, commodity futures, options or other
similar agreements relating to crude oil and natural gas.
Interest Rate Risk. The Company's variable rate bank debt is tied to prime
rate. If the interest rate on the Company's bank debt increases or decreases by
one percentage point, the Company's annual pretax income would change by
$19,990.
Credit Risk. Credit risk is the risk of loss as a result of nonperformance
by counter-parties of their contractual obligations. The Company's primary
credit risk is related to oil and gas production sold to various purchasers and
the receivables are generally not collateralized. At March 31, 2005, the
Company's largest credit risk associated with any single purchaser was $98,634.
The Company has not experienced any significant credit losses.
Energy Price Risk. Our most significant market risk is the pricing for
natural gas and crude oil. Our financial condition, results of operations, and
capital resources are highly dependent upon the prevailing market prices of, and
demand for, oil and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are
beyond our control. These factors include the level of global demand for
petroleum products, foreign supply of oil and gas, the establishment of and
20
compliance with production quotas by oil-exporting countries, weather
conditions, the price and availability of alternative fuels and overall economic
conditions, both foreign and domestic. We cannot predict future oil and gas
prices with any degree of certainty and expect energy prices to remain volatile
and unpredictable. If energy prices decline significantly, revenues and cash
flow would significantly decline. In addition, a noncash write-down of our oil
and gas properties could be required under full cost accounting rules if prices
declined significantly, even if it is only for a short period of time. See
Critical Accounting Policies and Estimates -- Ceiling Test under Item 7 of this
Form 10-K. Sustained weakness in oil and gas prices may also reduce the amount
of net oil and gas reserves that we can produce economically. Any reduction in
reserves, including reductions due to price fluctuations, can reduce the
borrowing base under our revolving credit facility and adversely affect our
liquidity and our ability to obtain capital for our exploration and development
activities. Similarly, any improvements in oil and gas prices can have a
favorable impact on our financial condition, results of operations and capital
resources. If the average oil price had increased or decreased by one cent per
barrel for fiscal 2005, our pretax income would have changed by $174. If the
average gas price had increased or decreased by one cent per mcf for fiscal
2005, our pretax income would have changed by $4,041.
Uncertainty of Reserve Information and Future Net Revenue Estimates.
Estimates of oil and gas reserves, by necessity, are projections based on
engineering data, and there are uncertainties inherent in the interpretation of
such data as well as the projection of future rates of production and the timing
of development expenditures. Reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that are difficult to
measure. Estimates of economically recoverable oil and gas reserves and of
future net cash flows depend upon a number of variable factors and assumptions,
such as future production, oil and gas prices, operating costs, development
costs and remedial costs, all of which may vary considerably from actual
results. As a result, estimates of the economically recoverable quantities of
oil and gas and of future net cash flows expected therefrom may vary
substantially. Moreover, there can be no assurance that our reserves will
ultimately be produced or that any undeveloped reserves will be developed. As
required by the SEC, the estimated discounted future net cash flows from proved
reserves are generally based on prices and costs as of the date of the estimate,
while actual future prices and costs may be materially higher or lower.
Reserve Replacement Risk. Our future success depends upon its ability to
find, develop or acquire additional, economically recoverable oil and gas
reserves. Our proved reserves will generally decline as reserves are depleted,
except to the extent that we can find, develop or acquire replacement reserves.
One offset to the obvious benefits afforded by higher product prices especially
for small to mid-cap companies in this industry, is that quality domestic oil
and gas reserves are becoming harder to find. Reserves to be produced from
undiscovered reservoirs appear to be smaller, and the risks to find these
reserves are greater. Reports from the Energy Information Administration
indicate that on-shore domestic finding costs are on the rise, and that the
average reserves added per well are declining.
Drilling and Operating Risks. Drilling and operating activities are
subject to many risks, including availability of workover and drilling rigs,
well blowouts, cratering, explosions, fires, formations with abnormal pressures,
pollution, releases of toxic gases and other environmental hazards and risks.
Any of these operating hazards could result in substantial losses to us. In
addition, we incur the risk that no commercially productive reservoirs will be
encountered and there is no assurance that we will recover all or any portion of
its investment in wells drilled or re-entered.
Marketability of Production. The marketability of our production depends
in part on the availability, proximity and capacity of natural gas gathering
systems, pipelines and processing facilities. Federal and state regulation of
oil and gas production and transportation, tax and energy policies, changes in
supply and demand and general economic conditions could all affect our ability
to produce and market our oil and gas.
21
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm.................23
Consolidated Balance Sheets.............................................24
Consolidated Statements of Operations...................................25
Consolidated Statements of Changes in Stockholders' Equity..............26
Consolidated Statements of Cash Flows...................................27
Notes to Consolidated Financial Statements..............................28
22
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Mexco Energy Corporation
We have audited the accompanying consolidated balance sheets of Mexco
Energy Corporation and Subsidiaries as of March 31, 2005 and 2004 and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended March 31, 2005. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. The Company is not
required to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audits included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mexco Energy
Corporation and Subsidiaries as of March 31, 2005 and 2004, and the results of
their operations and their cash flows for each of the three years in the period
ended March 31, 2005, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 5 to the financial statements, effective April 1,
2003, the Company adopted Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations, and changed its method of
accounting for asset retirement obligations.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
May 20, 2005
23
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEETS
As of March 31,
2005 2004
------------ ------------
ASSETS
Current assets
Cash and cash equivalents $ 85,209 $ 92,795
Accounts receivable:
Oil and gas sales 418,348 396,902
Trade 23,258 3,101
Related parties 2,103 --
Prepaid costs and expenses 7,362 32,382
------------ ------------
Total current assets 536,280 525,180
Investment in GazTex, LLC 282,126 --
Property and equipment, at cost
Oil and gas properties, using the full cost
method ($921,719 and $858,602 excluded
from amortization in 2005 and 2004, respectively) 18,376,974 16,959,560
Other 36,855 34,542
------------ ------------
18,413,829 16,994,102
Less accumulated depreciation,
depletion, and amortization 9,929,086 9,346,818
------------ ------------
Property and equipment, net 8,484,743 7,647,284
------------ ------------
$ 9,303,149 $ 8,172,464
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable - trade $ 111,675 $ 97,308
Income tax payable 48,127 --
Current portion of long-term debt -- 443,378
------------ ------------
Total current liabilities 159,802 540,686
Long-term debt 1,990,000 1,256,622
Asset retirement obligation 374,506 420,665
Deferred income tax liability 715,284 519,272
Minority interest 25,362 --
Commitments and contingencies -- --
Stockholders' equity
Preferred stock - $1.00 par value;
10,000,000 shares authorized; none outstanding -- --
Common stock - $0.50 par value;
40,000,000 shares authorized;
1,766,566 shares issued 883,283 883,283
Additional paid-in capital 3,826,592 3,784,493
Retained earnings 1,473,895 896,368
Treasury stock, at cost (145,575) (128,925)
------------ ------------
Total stockholders' equity 6,038,195 5,435,219
------------ ------------
$ 9,303,149 $ 8,172,464
============ ============
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
24
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended March 31,
2005 2004 2003
----------- ----------- -----------
Operating revenues:
Oil and gas $ 2,963,889 $ 2,909,953 $ 2,681,759
Other 5,937 5,402 267,354
----------- ----------- -----------
Total operating revenues 2,969,826 2,915,355 2,949,113
Operating expenses:
Production 780,233 942,093 848,513
Accretion of asset retirement obligation 24,735 24,246 --
Depreciation, depletion, and amortization 582,268 633,443 641,827
General and administrative 658,360 529,834 532,496
----------- ----------- -----------
Total operating expenses 2,045,596 2,129,616 2,022,836
----------- ----------- -----------
Operating profit 924,230 785,739 926,277
Other income (expense):
Interest income 746 764 981
Interest expense (89,154) (83,530) (96,337)
----------- ----------- -----------
Net other expense (88,408) (82,766) (95,356)
Minority interest in loss of subsidiary 14,314 -- --
----------- ----------- -----------
Earnings before income taxes and
cumulative effect of accounting change 850,136 702,973 830,921
Income tax expense:
Current 76,597 33,371 (13,026)
Deferred 196,012 137,489 171,139
----------- ----------- -----------
272,609 170,860 158,113
----------- ----------- -----------
Income before cumulative effect of accounting change 577,527 532,113 672,808
Cumulative effect of accounting change, net of tax -- (102,267) --
----------- ----------- -----------
Net income $ 577,527 $ 429,846 $ 672,808
=========== =========== ===========
Net income per common share:
Basic:
Income before cumulative effect
of accounting change $ 0.33 $ 0.31 $ 0.39
Cumulative effect, net of tax $ -- $ (0.06) $ --
----------- ----------- -----------
Net income $ 0.33 $ 0.25 $ 0.39
Diluted:
Income before cumulative effect
of accounting change $ 0.32 $ 0.30 $ 0.39
Cumulative effect, net of tax $ -- $ (0.06) $ --
----------- ----------- -----------
Net income $ 0.32 $ 0.24 $ 0.39
Pro forma amounts assuming, the new
method of accounting for asset retirement
obligations is applied retroactively:
Net income $ 532,113 $ 651,669
Basic net income per share $ 0.31 $ 0.37
Diluted net income per share $ 0.30 $ 0.37
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
25
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Retained
Additional Earnings Total
Common Stock Treasury Paid-In (Accumulated) Stockholders'
Par Value Stock Capital Deficit) Equity
------------ ----------- ----------- ------------- -------------
Balance, April 1, 2002 $ 883,283 $ -- $ 3,599,045 $ (206,286) $ 4,276,042
Net earnings -- -- -- 672,808 672,808
Purchase of stock -- (127,536) -- -- (127,536)
Issuance of warrants
for acreage -- -- 73,552 -- 73,552
Stock based
compensation -- -- 61,522 -- 61,522
----------- ----------- ----------- ----------- -----------
Balance, March 31, 2003 883,283 (127,536) 3,734,119 466,522 4,956,388
Net earnings -- -- -- 429,846 429,846
Purchase of stock -- (1,389) -- -- (1,389)
Profits from sale of stock
by insider -- -- 2,950 -- 2,950
Stock based
compensation -- -- 47,424 -- 47,424
----------- ----------- ----------- ----------- -----------
Balance, March 31, 2004 883,283 (128,925) 3,784,493 896,368 5,435,219
Net earnings -- -- -- 577,527 577,527
Purchase of stock -- (16,650) -- -- (16,650)
Stock based
compensation -- -- 42,099 -- 42,099
----------- ----------- ----------- ----------- -----------
Balance, March 31, 2005 $ 883,283 $ (145,575) $ 3,826,592 $ 1,473,895 $ 6,038,195
=========== =========== =========== =========== ===========
Share Activity
--------------
2005 2004 2003
---------- ---------- ----------
Common stock issued
At beginning of year 1,766,566 1,766,566 1,766,566
Issued -- -- --
Cancelled -- -- --
---------- ---------- ----------
At end of year 1,766,566 1,766,566 1,766,566
Held in treasury
At beginning of year (30,525) (30,244) --
Acquisitions (3,000) (281) (30,244)
---------- ---------- ----------
At end of year (33,525) (30,525) (30,244)
---------- ---------- ----------
Common shares outstanding at end
of year 1,733,041 1,736,041 1,736,322
========== ========== ==========
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
26
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended March 31,
2005 2004 2003
----------- ----------- -----------
Cash flows from operating activities:
Net earnings $ 577,527 $ 429,846 $ 672,808
Cumulative effect of accounting change -- 102,267 --
Adjustments to reconcile net income
to net cash provided by operating
activities:
Increase in deferred income taxes 196,012 137,489 171,139
Stock-based compensation 42,099 47,424 61,522
Depreciation, depletion, and amortization 582,268 633,443 641,827
Accretion of asset retirement obligations 24,735 24,246 --
Minority interest in loss of GazTex, LLC (14,314) -- --
(Increase) decrease in accounts receivable (43,706) 181,386 (193,089)
(Increase) decrease in prepaid expenses 25,020 (22,340) 14,080
Increase in income taxes payable 48,127 -- --
Increase (decrease) in accounts payable
and accrued expenses 13,860 (16,282) 1,403
----------- ----------- -----------
Net cash provided by operating activities 1,451,628 1,517,479 1,369,690
Cash flows from investing activities:
Additions to oil and gas properties (1,568,810) (982,872) (1,628,695)
Proceeds from sale of oil and gas properties and equipment 81,008 -- --
Additions to other property and equipment (2,313) (834) (4,927)
Investment in GazTex, LLC (282,126) -- --
----------- ----------- -----------
Net cash used in investing activities (1,772,241) (983,706) (1,633,622)
Cash flows from financing activities:
Acquisition of treasury stock (16,650) (1,389) (127,536)
Profits from sale of stock by insider -- 2,950 --
Reduction of capital lease obligations -- (61,086) (24,943)
Reduction of long-term debt (660,000) (770,000) (470,000)
Proceeds from long term debt 950,000 320,000 910,000
Minority interest contributions 39,677 -- --
----------- ----------- -----------
Net cash (used in) provided by
financing activities 313,027 (509,525) 287,521
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents (7,586) 24,248 23,589
Cash and cash equivalents at beginning of year 92,795 68,547 44,958
----------- ----------- -----------
Cash and cash equivalents at end of year $ 85,209 $ 92,795 $ 68,547
=========== =========== ===========
Interest paid $ 84,662 $ 83,196 $ 94,792
Income taxes paid (recovered) $ 12,269 $ 50,000 $ (117,056)
Supplemental disclosure of non-cash investing and financing activities:
Fair value of warrants issued for
oil and gas properties $ -- $ -- $ 73,552
Acquisition of equipment under capital leases $ -- $ -- $ 81,182
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
27
MEXCO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations
Mexco Energy Corporation (a Colorado Corporation), its wholly owned subsidiary,
Forman Energy Corporation, and its 90% owned subsidiary, OBTX, LLC (a Delaware
Limited Liability Company) (collectively, the "Company") are engaged in the
exploration, development and production of natural gas, crude oil, condensate
and natural gas liquids (NGLs). OBTX, LLC was formed on April 8, 2004, and is
included in the consolidated financial statements since its date of formation.
Although most of the Company's oil and gas interests are centered in West Texas,
the Company owns producing properties and undeveloped acreage in ten states.
Although most of the Company's oil and gas interests are operated by others, the
Company operates several properties in which it owns an interest.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the
accounts of Mexco Energy Corporation and its wholly owned and majority owned
subsidiaries. All significant intercompany balances and transactions have been
eliminated.
Use of Estimates. In preparing financial statements in conformity with
accounting principles generally accepted in the United States of America,
management is required to make informed judgments and estimates that affect the
reported amounts of assets and liabilities as of the date of the financial
statements and affect the reported amounts of revenues and expenses during the
reporting period. Although management believes its estimates and assumptions are
reasonable, actual results may differ materially from those estimates.
Significant estimates affecting these financial statements include the estimated
quantities of proved oil and gas reserves, the related present value of
estimated future net cash flows and the future development, dismantlement and
abandonment costs.
Cash and Cash Equivalents. The Company considers all highly liquid debt
instruments purchased with maturities of three months or less and money market
funds to be cash equivalents. The Company maintains its cash in bank deposit
accounts and money market funds, some of which are not federally insured. The
Company has not experienced any losses in such accounts and believes it is not
exposed to any significant credit risk.
Oil and Gas Properties. Oil and gas properties are accounted for using the full
cost method of accounting as defined by the Securities and Exchange Commission
("SEC"). Under this method of accounting, the costs of unsuccessful, as well as
successful, exploration and development activities are capitalized as property
and equipment. This includes any internal costs that are directly related to
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities. Effective with the
adoption of SFAS No. 143 in fiscal 2004, the carrying amount of oil and gas
properties also includes estimated asset retirement costs recorded based on the
fair value of the asset retirement obligation when incurred. Generally, no gains
or losses are recognized on the sale or disposition of oil and gas properties.
Excluded Costs. Oil and gas properties include costs that are excluded from
capitalized costs being amortized. These amounts represent investments in
unproved properties and major development projects. These costs are excluded
until proved reserves are found or until it is determined that the costs are
impaired. All costs excluded are reviewed at least quarterly to determine if
impairment has occurred. The amount of any impairment is transferred to the
capitalized costs being amortized (the depreciation, depletion and amortization
(DD&A) pool) or a charge is made against earnings for those international
operations where a reserve base has not yet been established. Impairments
transferred to the DD&A pool increase the DD&A rate.
Depreciation, Depletion and Amortization. The depreciable base for oil and gas
properties includes the sum of capitalized costs net of accumulated DD&A,
estimated future development costs and asset retirement costs not accrued in oil
and gas properties, less costs excluded from amortization and salvage. The
depreciable base of oil and gas properties and mineral investments are amortized
using the unit-of-production method.
28
Ceiling Test. Under the full cost method of accounting, a ceiling test is
performed each quarter. The full cost ceiling test is an impairment test
prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit,
on a country-by-country basis, on the book value of oil and gas properties. The
capitalized costs of proved oil and gas properties, net of accumulated DD&A and
the related deferred income taxes, may not exceed the estimated future net cash
flows from proved oil and gas reserves, excluding future cash outflows
associated with settling asset retirement obligations that have been accrued on
the balance sheet, generally using prices in effect at the end of the period
held flat for the life of production and including the effect of derivative
contracts that qualify as cash flow hedges, discounted at 10%, net of related
tax effects, plus the cost of unevaluated properties and major development
projects excluded from the costs being amortized. If capitalized costs exceed
this limit, the excess is charged to expense and reflected as additional
accumulated DD&A.
Asset Retirement Obligations ("ARO"). The Company has significant obligations to
plug and abandon natural gas and crude oil wells and related equipment at the
end of oil and gas production operations. The Company records the fair value of
a liability for an ARO in the period in which it is incurred and a corresponding
increase in the carrying amount of the related asset. Subsequently, the asset
retirement costs included in the carrying amount of the related asset are
allocated to expense using the units of production method. In addition,
increases in the discounted ARO liability resulting from the passage of time are
reflected as accretion expense in the Consolidated Statement of Operations.
Estimating the future ARO requires management to make estimates and judgments
regarding timing and existence of a liability, as well as what constitutes
adequate restoration. The Company uses the present value of estimated cash flows
related to its ARO to determine the fair value. Inherent in the present value
calculation are numerous assumptions and judgments including the ultimate costs,
inflation factors, credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental and political environments. To
the extent future revisions to these assumptions impact the present value of the
existing ARO liability, a corresponding adjustment is made to the related asset.
Long Term Investment in GazTex, LLC. The Company accounts for its investment in
a limited liability company on the equity basis and adjusts the investment
balance to agree with its equity in the underlying assets of the entity.
Other Property and Equipment. Provisions for depreciation of office furniture
and equipment are computed on the straight-line method based on estimated useful
lives of five to ten years.
Revenue Recognition and Gas Balancing. Oil and gas sales and resulting
receivables are recognized when the product is delivered to the purchaser and
title has transferred. Sales are to credit-worthy energy purchasers with
payments generally received within 60 days of transportation from the well site.
The Company has historically had little, if any, uncollectible oil and gas
receivables; therefore, an allowance for uncollectible accounts is not required.
Gas imbalances are accounted for under the sales method whereby revenues are
recognized based on production sold. A liability is recorded when the Company's
excess takes of natural gas volumes exceed its estimated remaining recoverable
reserves (over produced). No receivables are recorded for those wells where the
Company has taken less than its ownership share of gas production (under
produced). The Company has no significant gas imbalances.
Income Per Common Share. Basic income per share is computed by dividing net
income by the weighted average number of shares outstanding during the period.
Diluted income per share is computed by dividing net income by the weighted
average number of common shares and dilutive potential common shares (stock
options and warrants) outstanding during the period. In periods where losses are
reported, the weighted-average number of common shares outstanding excludes
potential common shares, because their inclusion would be anti-dilutive. The
following is a reconciliation of the number of shares used in the calculation of
basic income per share and diluted income per share for the periods ended March
31:
29
2005 2004 2003
--------- --------- ---------
Weighted average number of common shares
outstanding, basic 1,734,726 1,736,047 1,741,462
Incremental shares from the assumed exercise of
dilutive stock options 66,441 66,253 5,369
--------- --------- ---------
Dilutive potential common shares 1,801,167 1,802,300 1,746,831
========= ========= =========
Outstanding options and warrants to purchase 90,000, 10,000 and 388,500 shares
at March 31, 2005, 2004, and 2003, respectively, were not included in the
computation of diluted net earnings per share because the exercise price of the
options or warrants was greater than the average market price of the common
shares and, therefore, the effect would be anti-dilutive.
Income Taxes. The Company recognizes deferred tax assets and liabilities for the
future tax consequences of temporary differences between the carrying amounts of
assets and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates applicable to the years in
which those differences are expected to be settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in net income in
the period that includes the enactment date.
Stock Options and Warrants. The Company accounts for employee stock option
grants in accordance with Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees," as amended by Financial Accounting
Standards Board ("FASB") Interpretation No. 44, "Accounting for Certain
Transactions involving Stock Compensation," an interpretation of APB Opinion No.
25. The Company applies the intrinsic-value method in accounting for its
employee stock options and records no compensation costs for its stock option
awards to employees. The Company recognizes compensation cost related to stock
options awarded to independent consultants based on fair value of the options at
date of grant.
If compensation cost for the Company's stock option plan had been determined
based on the fair value at the grant dates for all employee awards under the
plan, net income, basic income per common share and diluted income per common
share would have been as follows:
2005 2004 2003
----------- ----------- -----------
Net income, as reported $ 577,527 $ 429,846 $ 672,808
Deduct: Stock-based employee compensation expense
determined under fair value based method
(SFAS 123), net of tax (90,081) (86,070) (63,133)
----------- ----------- -----------
Net income, pro forma $ 487,446 $ 343,776 $ 609,675
=========== =========== ===========
Basic income per share:
As reported $ 0.33 $ 0.25 $ 0.39
Pro forma $ 0.28 $ 0.20 $ 0.35
Diluted income per share:
As reported $ 0.32 $ 0.24 $ 0.39
Pro forma $ 0.27 $ 0.19 $ 0.35
Financial Instruments. Cash and money market funds, stated at cost, are
available upon demand and approximate fair value. Interest rates associated with
the Company's long-term debt are linked to current market rates. As a result,
management believes that the carrying amount approximates the fair value of the
Company's credit facilities. All financial instruments are held for purposes
other than trading.
Recent Accounting Pronouncements. FASB Staff Position (FSP) FAS 109-1,
"Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax
Deduction on Qualified Production Activities Provided by the American Jobs
Creation Act of 2004," provides guidance on the application of SFAS No. 109,
"Accounting for Income Taxes," to the tax deduction on qualified production as
provided for in the American Jobs Creation Act of 2004 (Jobs Act). FSP FAS 109-1
provides that the deduction should be treated as a special deduction under
paragraph 231 of SFAS No. 109. This deduction takes effect beginning in 2005
and, therefore, has no impact on the current year financial statements. The
Company is currently assessing the effect of FAS 109-1 on the fiscal 2006
financial statements.
30
In December 2004, the FASB issued Statement of Financial Accounting Standards
No. 123 (revised 2004) "Share-Based Payments" ("SFAS 123R"). SFAS 123R requires
that the cost from all share-based payment transactions, including stock
options, be recognized in the financial statements at fair value. The Company
currently uses the intrinsic-value method to account for these share-based
payments. For public companies, SFAS 123R is effective for fiscal years
beginning after June 15, 2005. The Company will adopt the provisions of this
statement in the first quarter of fiscal 2007 and is currently assessing the
effect of SFAS 123R on the financial statements.
The SEC issued Staff Accounting Bulletin (SAB) No. 106 regarding the application
of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for
Asset Retirement Obligations," by oil and gas producing entities that follow the
full cost accounting method. SAB No. 106, which was adopted in the third quarter
of fiscal 2005, states that after adoption of SFAS No. 143, the future cash
outflows associated with settling asset retirement obligations that have been
accrued on the balance sheet should be excluded from the present value of
estimated future net cash flows used for the full cost ceiling test calculation.
It also states that estimated dismantlement and abandonment costs in future
development activities be included in the calculation of depreciation, depletion
and amortization. The adoption of SAB No. 106 did not have any material impact
on the Company's financial statements.
3. Long-Term Debt
The Company has a revolving credit agreement with Bank of America, N.A.
("Bank"), which provides for a credit facility of $5,000,000, subject to a
borrowing base determination. Effective August 15, 2004, the credit agreement
was amended with a maturity date of April 1, 2006. On July 29, 2004, the
borrowing base was redetermined and increased to $2,500,000 with no monthly
commitment reductions. As of March 31, 2005, the balance outstanding under this
agreement was $1,990,000. No principal payments are anticipated to be required
through March 31, 2006 based on the revised borrowing base. A letter of credit
for $50,000, in lieu of a plugging bond with the Texas Railroad Commission
covering the properties the Company operates, is also outstanding under the
facility. The borrowing base is subject to redetermination on or about August 1,
of each year. Amounts borrowed under this agreement are collateralized by the
common stock of Forman and the Company's oil and gas properties. Interest under
this agreement is payable monthly at prime rate (5.75% and 4.00% at March 31,
2005 and 2004, respectively). This agreement generally restricts the Company's
ability to transfer assets or control of the Company, incur debt, extend credit,
change the nature of the Company's business, substantially change management
personnel or pay cash dividends.
4. Other Income
During the third quarter of fiscal 2003 the Company received proceeds of
$254,862, before expenses of $101,945, resulted from the settlement of a class
action lawsuit against a gas purchaser involving contract price disputes.
5. Asset Retirement Obligations
The Company's asset retirement obligations relate to the plugging and
abandonment of oil and gas properties. The Company adopted SFAS No. 143 on April
1, 2003. SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recorded in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
The change resulted in a cumulative effect charge to net income of ($102,267)
net of tax, or ($0.06) per share. Additionally, the Company recorded an asset
retirement obligation liability of $358,419 and an increase to net properties
and equipment and other assets of $210,206 upon adoption of SFAS No. 143.
The asset retirement obligation, which is included on the consolidated balance
sheet, was $395,046 at March 31, 2005. The current portion of the asset
retirement obligation as of March 31, 2005, was $20,540 and is included on the
consolidated balance sheet in accounts payable and other accrued expenses.
Accretion expense for fiscal 2005 and 2004 was $24,735 and $24,246,
respectively.
31
The following table provides a rollforward of the asset retirement obligation
for the fiscal years ended March 31, 2005 and 2004:
2005 2004
--------- ---------
Carrying amount of asset retirement obligations as of April 1 $ 420,665 $ 358,419
Liabilities incurred 4,831 48,321
Liabilities settled (55,185) (10,321)
Accretion expense 24,735 24,246
--------- ---------
Carrying amount of asset retirement obligations as of March 31 $ 395,046 $ 420,665
========= =========
6. Income Taxes
Deferred tax assets and liabilities are the result of temporary differences
between the financial statement carrying values and the tax bases of assets and
liabilities. Significant components of net deferred tax assets (liabilities) at
March 31 are as follows:
2005 2004
----------- -----------
Deferred tax assets:
Percentage depletion carryforwards $ 411,907 $ 442,907
Vacation accrual 2,714 2,636
Deferred compensation 69,587 56,536
Asset retirement obligation 122,464 130,406
Other -- 1,777
----------- -----------
606,672 634,262
Deferred tax liabilities:
Excess financial accounting bases over tax bases
of property and equipment (1,321,956) (1,153,534)
----------- -----------
Net deferred tax liabilities $ (715,284) $ (519,272)
=========== ===========
As of March 31, 2005, the Company has statutory depletion carryforwards of
approximately $1,329,000, which do not expire.
A reconciliation of the provision for income taxes to income taxes computed
using the federal statutory rate for years ended March 31 follows:
2005 2004 2003
--------- --------- ---------
Tax expense at statutory rate $ 284,180 $ 239,011 $ 282,513
Depletion in excess of basis -- (39,563) (86,170)
Effect of graduated rates (25,075) (21,089) (24,928)
Revision of prior year estimates 2,526 -- (13,026)
Other 10,978 (7,499) (276)
--------- --------- ---------
$ 272,609 $ 170,860 $ 158,113
========= ========= =========
Effective tax rate 33% 24% 19%
========= ========= =========
7. Exploration Agreement
On December 5, 2002, the Company entered into an exploration agreement with
Falcon Bay Operating, LLC. Pursuant to such agreement, the Company obtained the
right to purchase and inventory seismic data and acreage in shallow water areas
of Texas and Louisiana. In consideration for the right to obtain four such
prospects, the Company issued warrants to purchase 107,500 shares of common
stock at an exercise price of $5.00 per share. Such warrants were exercisable
for a period of two years from date of grant and expired, unexercised on
December 5, 2004. This agreement provided for the issuance of additional
warrants, exercisable for two years at the same exercise price, covering 322,500
shares upon exercise of the Company's right to participate in a total of four
prospects. Both parties have elected not to participate in any additional
prospects; therefore, no further warrants will be issued.
32
8. Investment in GazTex, LLC
The Company's long-term assets consist of an investment in GazTex, LLC, a
Russian company owned 50% by OBTX, LLC, accounted for by the equity method.
OBTX, LLC is a Delaware limited liability company in which Mexco owns 90% of the
interest, with the remaining 10% divided equally among three individuals, one of
whom is Arden Grover, a director of Mexco Energy Corporation. All geological and
geophysical costs associated with the evaluation of Russian properties have been
paid 90% by Mexco Energy Corporation and 10% by the other three owners of OBTX,
LLC. These amounts will not be reimbursed by GazTex, LLC as originally
anticipated in our December 31, 2004 quarterly financials, but instead represent
an investment in GazTex, LLC. GazTex, LLC was formed during fiscal 2005 and
through March 31, 2005 has no operations other than the evaluation activity.
Through March 31, 2005, the Company has $282,126 classified as a long-term
investment in GazTex, LLC. The 10% interest in OBTX, LLC is included in the
Company's financial statements as a minority interest. OBTX, LLC, plans to
participate in any Russian venture entered into and own a 50% interest. Through
March 31, 2005, the Company has expensed organization costs of $46,514 to set up
OBTX, LLC and has expensed $83,213 in consulting costs for the initial
evaluation of projects that have been discontinued.
9. Major Customers
Currently, the Company operates exclusively within the United States and its
revenues and operating income are derived predominately from the oil and gas
industry. Oil and gas production is sold to various purchasers and the
receivables are unsecured. Historically, the Company has not experienced
significant credit losses on its oil and gas accounts and management is of the
opinion that significant credit risk does not exist. Management is of the
opinion that the loss of any one purchaser would not have an adverse effect on
the ability of the Company to sell its oil and gas production.
In fiscal 2005, 2004, and 2003, one purchaser accounted for 21%, 29%, and 28%,
respectively, of revenues. At March 31, 2005, accounts receivable from the
purchaser was approximately 24% of oil and gas accounts receivable.
10. Oil and Gas Costs
The costs related to the oil and gas activities of the Company were incurred as
follows:
Year Ended March 31,
------------------------------------------
2005 2004 2003
---------- ---------- ----------
Property acquisition costs
Proved $1,203,768 $ 339,519 $ 64,090
Unproved U.S. 104,713 184,912 673,690
Unproved Russia -- 41,596 --
Exploration costs 78,753 4,757 55,543
Development costs 193,446 453,684 990,106
The Russian costs included in 2004 have been contributed to GazTex, LLC
and are included on the consolidated balance sheet in the long-term
investment in GazTex, LLC.
The Company had the following aggregate capitalized costs relating to the
Company's oil and gas property activities at March 31:
33
2005 2004 2003
----------- ----------- -----------
Proved oil and gas properties $17,098,091 $15,758,031 $14,596,072
Unproved oil and gas properties:
subject to amortization 357,164 342,927 387,166
not subject to amortization-U.S 921,719 817,006 673,690
not subject to amortization-Russia -- 41,596 --
----------- ----------- -----------
18,376,974 16,959,560 15,656,928
Less accumulated depreciation,
depletion, and amortization 9,899,582 9,320,174 8,637,902
----------- ----------- -----------
$ 8,477,392 $ 7,639,386 $ 7,019,026
=========== =========== ===========
The cost of certain oil and gas leases that the Company has acquired, but not
evaluated, have been excluded in computing amortization of the full cost pool.
The Company will begin to amortize these properties when the projects are
evaluated, which is currently estimated to be within the following year. Costs
excluded from amortization at March 31, 2005 and 2004 total $921,719 and
$858,602, respectively. No impairment exists for these properties at March 31,
2005 based on geological studies.
Depreciation, depletion, and amortization amounted to $6.84, $6.24 and $5.64 per
equivalent barrel of production for the years ended March 31, 2005, 2004, and
2003, respectively.
11. Stockholders' Equity
In fiscal 2003, the board of directors authorized the use of up to $250,000 to
repurchase shares of the Company's common stock. During fiscal 2003, the Company
repurchased 30,244 shares at an aggregate cost of $127,536 for the treasury
account. For the fiscal 2004, the board of directors repurchased 281 shares at
an aggregate cost of $1,389 for the treasury account. During fiscal 2005, the
Company purchased 3,000 shares at an aggregate cost of $16,650 for the treasury
account.
During the last quarter of fiscal 2004, the Chairman of the board paid the
Company $2,950, representing profits on stock sold which he held less than six
months. Such payment was made in accordance with Section 16(b) of the Securities
Exchange Act of 1934.
12. Stock Options and Warrants
The Company adopted an employee incentive stock plan effective September 15,
1997. Under the plan, 350,000 shares are available for distribution. Awards,
granted at the discretion of the compensation committee of the board of
directors, include stock options of restricted stock. Stock options may be an
incentive stock option or a nonqualified stock option. Options to purchase
common stock under the plan are granted at the fair market value of the common
stock at the date of grant, become exercisable to the extent of 25% of the
shares optioned on each of four anniversaries of the date of grant, expire ten
years from the date of grant and are subject to forfeiture if employment
terminates. Restricted stock awards may be granted with a condition to attain a
specified goal. The purchase price will be at least $5.00 per share of
restricted stock. The awards of restricted stock must be accepted within 60 days
and will vest as determined by agreement. Holders of restricted stock have all
rights of a shareholder of the Company.
In September 2004, the Board of Directors of the Company adopted the 2004
Incentive Stock Plan to replace, modify and extend the termination date of the
September 15, 1997 stock plan to September 14, 2009. This new plan provides for
the award of stock options up to 375,000 shares of which 125,000 may be the
subject of stock grants without restrictions and without payment by the
recipient and stock awards of up to 125,000 shares with restrictions including
payment for the shares and employment of not less than three years from the date
of the award. The terms of the stock options are similar to those of the
existing stock option plan except that the term of the Plan is five years from
the date of its adoption.
34
During fiscal 2005, options for 40,000 shares were granted. Of these, 10,000
options were granted to contract consultants. The exercise price of all options
granted equaled or exceeded the market price of the stock on the date of grant.
Additional information with respect to the Plan's stock option activity for
options issued to employees and directors is as follows:
Weighted
Number Average
of Shares Exercise Price
--------- --------------
Options outstanding, at April 1, 2002 150,000 $ 6.07
Granted 31,000 4.00
Exercised -- --
Forfeited -- --
---------- ----------
Options outstanding, at March 31, 2003 181,000 5.71
Granted 39,000 6.00
Exercised -- --
Forfeited -- --
---------- ----------
Options outstanding, at March 31, 2004 220,000 5.76
Granted 30,000 6.52
Exercised -- --
Forfeited -- --
---------- ----------
Options outstanding, at March 31, 2005 250,000 $ 5.85
========== ==========
Options exercisable at March 31, 2003 110,000 $ 6.40
Options exercisable at March 31, 2004 142,750 $ 6.08
Options exercisable at March 31, 2005 170,250 $ 5.94
Weighted average grant date fair value of stock options granted to employees and
directors during fiscal 2005, 2004, and 2003 were $3.98, $4.82 and $3.72,
respectively. These values were determined using a Binomial option-pricing
model. The model values options based on the stock price at the grant date, the
expected life of the option, the estimated volatility of the stock, the expected
dividend payments and the risk-free interest rate over the expected life of the
option. The Company considers the Binomial model more accurate than the
Black-Scholes model, in that it recognizes the ability to exercise before
expiration once an option is vested. The assumptions used in the Binomial models
were as follows for stock options granted in fiscal 2005, 2004 and 2003:
2005 2004 2003
---------- ---------- ----------
Expected volatility 62.99% 67.46% 134.07%
Expected dividend yield 0.00% 0.00% 0.00%
Risk-free rate of return 3.99% 3.40% 5.40%
Expected life of options 6.3 years 7 years 7 years
The option valuation models were developed for use in estimating the fair value
of traded options that have no vesting restrictions and are fully transferable.
In addition, option valuation models require the input of highly subjective
assumptions including expected stock price volatility.
The following tables summarize information about employee and directors stock
options outstanding and exercisable at March 31, 2005:
35
Stock Options Outstanding
Weighted Average
Number of Remaining Weighted
Range of Shares Contractual Average
Exercise Prices Outstanding Life in Years Exercise Price
--------------- ----------- ------------------ --------------
$7.50-$7.75 50,000 3.56 $7.60
$6.70-$6.75 40,000 7.54 $6.73
$6.00-$6.17 49,000 7.50 $6.03
$5.25 60,000 4.98 $5.25
$4.00 51,000 6.88 $4.00
---------
250,000
Stock Options Exercisable
Number of Weighted
Range of Shares Average
Exercise Prices Exercisable Exercise Price
--------------- ----------- --------------
$7.50-$7.75 50,000 $7.60
$6.75 20,000 $6.75
$6.00 9,750 $6.00
$5.25 60,000 $5.25
$4.00 30,500 $4.00
---------
170,250
Since the Company applies the intrinsic-value method in accounting for its
employee stock options, it generally records no compensation cost for its stock
option awards to employees. The Company recognizes expense related to stock
options awarded to independent consultants and contractors based on fair value
of the options at date of grant. Additional information with respect to stock
option and warrant activity for options and warrants granted to outside
consultants and contractors is as follows:
Weighted
Number Average
of Shares Exercise Price
--------- --------------
Options outstanding, at April 1, 2002 80,000 $ 6.25
Granted 127,500 4.84
Exercised -- --
Forfeited -- --
------- -------
Options outstanding, at March 31, 2003 207,500 5.39
Granted 10,000 7.00
Exercised -- --
Forfeited -- --
------- -------
Options outstanding, at March 31, 2004 217,500 5.83
Granted 10,000 5.65
Exercised -- --
Forfeited* 107,500 5.00
------- -------
Options outstanding, at March 31, 2005 120,000 $ 5.89
======= =======
Options exercisable at March 31, 2003 160,000 $ 5.50
Options exercisable at March 31, 2004 180,000 $ 5.48
Options exercisable at March 31, 2005 90,000 $ 5.75
*Warrants issued December 5, 2002 to purchase 107,500 shares of common stock at
an exercise price of $5.00 expired December 5, 2004.
Weighted average grant date fair value of stock options and warrants granted to
outside consultants and contractors during fiscal 2005, 2004, and 2003 were
$3.23, $5.46 and $1.16, respectively. These values were determined using a
Binomial option-pricing model. The model values options based on the stock price
at the grant date, the expected life of the option, the estimated volatility of
the stock, the expected dividend payments and the risk-free interest rate over
the expected life of the option. The assumptions used in the Binomial models
were as follows for stock options granted in fiscal 2005, 2004 and 2003:
36
2005 2004 2003
------- ------- -------
Expected volatility 65.91% 62.52% 90.09%
Expected dividend yield 0.00% 0.00% 0.00%
Risk-free rate of return 4.01% 3.81% 2.39%
Expected life of options 5 years 7 years 3 years
The option valuation models were developed for use in estimating the fair value
of traded options that have no vesting restrictions and are fully transferable.
In addition, option valuation models require the input of highly subjective
assumptions including expected stock price volatility.
The following tables summarize information about outside consultants and
contractors stock options and warrants outstanding and exercisable at March 31,
2005:
Stock Options/Warrants Outstanding
Weighted Average
Number of Remaining Weighted
Range of Shares Contractual Average
Exercise Prices Outstanding Life in Years Exercise Price
--------------- ----------- ---------------- --------------
$7.50-$7.75 20,000 3.47 $7.63
$7.00 10,000 8.65 $7.00
$6.75 30,000 5.82 $6.75
$5.65 10,000 4.93 $5.65
$5.25 20,000 4.98 $5.25
$4.00 30,000 6.97 $4.00
-----------
120,000
Stock Options/Warrants Exercisable
Number of Weighted
Range of Shares Average
Exercise Prices Exercisable Exercise Price
--------------- ----------- --------------
$7.50-$7.75 20,000 $7.63
$7.00 2,500 $7.00
$6.75 30,000 $6.75
$5.25 20,000 $5.25
$4.00 17,500 $4.00
-----------
90,000
The Company recognizes expense related to stock options awarded to independent
consultants based on fair value of the options at date of grant. Total expense
related to these awards was $42,099, $47,424 and $61,522 for fiscal 2005, 2004
and 2003, respectively. The Company capitalizes fair value of warrants as part
of the leasehold cost of the acreage acquired in connection with the issuance of
the warrants.
13. Related Party Transactions
Related party transactions with the majority stockholder for the years ended
March 31, 2005, 2004, and 2003 relate to shared office expenditures. The total
billed to the stockholder for years ended March 31, 2005, 2004 and 2003 was
$6,612, $18,118 and $10,016, respectively.
Effective January 1, 2000, the Company entered into an agreement with the
husband of an officer and director of the Company to provide geological
consulting services. Amounts paid under this contract were $13,835, $8,094 and
$19,251 for the years ended March 31, 2005, 2004 and 2003, respectively.
37
Arden Grover is a director of the Company and owns 3 1/3% of OBTX, LLC. Mr.
Grover serves as a member of the board of directors of both OBTX, LLC and its
50% owned Russian subsidiary GazTex LLC. Since inception of this venture, Mr.
Grover has invested $13,226 as his share of 3 1/3% ownership of OBTX, LLC.
During the year ending March 31, 2004, a member of the board of directors, also
a Company employee, entered into an agreement with Deepwater Resources, L.P. and
Gary Martin, whereby he receives a 1.5% overriding royalty on certain leases
related to the Lodgepole Prospect in Stark County, North Dakota. In January
2004, the Company purchased a one-quarter interest in these leases and/or
options to lease.
During the year ending March 31, 2003, a member of the board of directors, also
a Company employee, entered into an agreement with Falcon Bay, LLC, whereby he
receives a commission from Falcon Bay Operating, LLC for any transactions
consummated between Falcon Bay Operating, LLC and the Company in the course of
the Exploration Agreement.
14. Oil and Gas Reserve Data (Unaudited)
The estimates of the Company's proved oil and gas reserves, which are located
entirely within the United States, were prepared in accordance with the
guidelines established by the SEC and FASB. These guidelines require that
reserve estimates be prepared under existing economic and operating conditions
at year-end, with no provision for price and cost escalators, except by
contractual agreement. The estimates as of March 31, 2005, 2004, and 2003 are
based on evaluations prepared by Joe C. Neal and Associates, Petroleum
Consultants.
Management emphasizes that reserve estimates are inherently imprecise and are
expected to change as new information becomes available and as economic
conditions in the industry change. The following estimates of proved reserves
quantities and related standardized measure of discounted net cash flow are
estimates only, and do not purport to reflect realizable values or fair market
values of the Company's reserves.
Changes in Proved Reserve Quantities (Unaudited):
2005 2004 2003
--------------------------- --------------------------- ---------------------------
Bbls Mcf Bbls Mcf Bbls Mcf
----------- ----------- ----------- ----------- ----------- -----------
Proved reserves,
beginning of year 132,000 7,917,000 150,000 7,931,000 237,000 10,182,000
Revision of previous
estimates 31,000 (660,000) 2,000 214,000 (66,000) (1,746,000)
Purchase of minerals
in place 3,000 482,000 -- 260,000 -- 22,000
Extensions and
discoveries 2,000 30,000 -- -- 2,000 12,000
Sales of minerals
in place -- (38,000) -- -- -- --
Production (17,000) (404,000) (20,000) (488,000) (23,000) (539,000)
----------- ----------- ----------- ----------- ----------- -----------
Proved reserves,
end of year 151,000 7,327,000 132,000 7,917,000 150,000 7,931,000
=========== =========== =========== =========== =========== ===========
Proved Developed Reserves (Unaudited):
Beginning of year 77,000 4,274,000 94,000 4,518,000 144,000 5,159,000
End of year 108,000 4,597,000 77,000 4,274,000 94,000 4,518,000
38
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves (Unaudited):
March 31,
----------------------------------------------
2005 2004 2003
------------ ------------ ------------
Future cash inflows $ 49,785,000 $ 46,230,000 $ 49,820,000
Future production and development costs (12,518,000) (12,225,000) (13,284,000)
Future income taxes (a) (8,517,000) (7,761,000) (8,444,000)
------------ ------------ ------------
Future net cash flows 28,750,000 26,244,000 28,092,000
Annual 10% discount for estimated timing of cash flows (12,591,000) (11,482,000) (12,120,000)
------------ ------------ ------------
Standardized measure of discounted future net cash flows $ 16,159,000 $ 14,762,000 $ 15,972,000
============ ============ ============
(a) Future income taxes are computed using effective tax rates on future net
cash flows before income taxes less the tax bases of the oil and gas
properties and effects of statutory depletion.
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
Relating to Proved Oil and Gas Reserves
Year Ended March 31,
----------------------------------------------
2005 2004 2003
------------ ------------ ------------
Sales of oil and gas produced,
net of production costs $ (2,184,000) $ (1,968,000) $ (1,833,000)
Net changes in price and production costs 2,167,000 (1,697,000) 12,946,000
Changes in previously estimated
development costs (539,000) -- 512,000
Revisions of quantity estimates (1,053,000) 524,000 (5,103,000)
Net change due to purchases and sales of
minerals in place 1,305,000 681,000 77,000
Extensions and discoveries,
less related costs 156,000 -- 87,000
Net change in income taxes (422,000) 436,000 (2,180,000)
Accretion of discount 1,912,000 2,077,000 1,193,000
Changes in timing of estimated cash
flows and other 55,000 (1,263,000) 969,000
------------ ------------ ------------
Changes in standardized measure 1,397,000 (1,210,000) 6,668,000
Standardized measure, beginning of year 14,762,000 15,972,000 9,304,000
------------ ------------ ------------
Standardized measure, end of year $ 16,159,000 $ 14,762,000 $ 15,972,000
============ ============ ============
15. Selected Quarterly Financial Data (Unaudited)
FISCAL 2005
--------------------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
-------- -------- -------- --------
Net sales $791,476 $774,966 $722,452 $674,995
Operating profit 250,596 287,220 225,160 161,254
Net income 172,406 183,359 119,060 102,702
Net income per share-basic 0.09 0.11 0.07 0.06
Net income per share-diluted 0.09 0.10 0.07 0.06
FISCAL 2004
--------------------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
-------- -------- -------- --------
Net sales $723,258 $650,783 $768,852 $767,060
Operating profit 254,264 123,570 196,292 211,613
Net income before cumulative effect 204,628 57,255 118,470 151,760
Net income per share-basic (1) 0.12 0.03 0.07 0.03
Net income per share-diluted (1) 0.12 0.03 0.06 0.03
(1) First quarter of fiscal 2004 includes a cumulative effect of change in
accounting principle (Cumulative Effect) loss of $0.06 related to the
adoption of Statement of Financial Accounting Standards (SFAS) No. 143,
Asset Retirement Obligations.
39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures to ensure that the information we
must disclose in our filings with the SEC is recorded, processed, summarized and
reported on a timely basis. Our principal executive officer and principal
financial officer have reviewed and evaluated the effectiveness of our
disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e), as of March 31, 2005. Based on such evaluation, such officers
have concluded that, as of March 31, 2005, our disclosure controls and
procedures were effective in timely alerting them to material information
relating to us (and our consolidated subsidiaries) required to be included in
our periodic SEC filings. There has been no change in our internal control over
financial reporting during the year ended March 31, 2005 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
ITEM 9B. OTHER INFORMATION
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required regarding Directors of the Company and compliance with
Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
reference to the Company's Proxy Statement for its Annual Meeting of
Stockholders, which will be filed with the SEC not later than July 30, 2005.
Pursuant to Item 401(b) of Regulation S-K, the information required by this item
with respect to executive officers of the Company is set forth in Part I of this
report.
ITEM 11. EXECUTIVE COMPENSATION
The information required in this item is incorporated by reference from the
Company's Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the SEC not later than July 30, 2005.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required in this item is incorporated by reference from the
Company's Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the SEC not later than July 30, 2005.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in this item is incorporated by reference from the
Company's Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the SEC not later than July 30, 2005.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required in this item is incorporated by reference from the
Company's Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the SEC not later than July 30, 2005.
40
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Schedules.
See "Index to Consolidated Financial Statements" set forth in Item 8
of this Form 10-K.
No schedules are required to be filed because of the absence of
conditions under which they would be required or because the required
information is set forth in the financial statements or notes thereto
referred to above.
3. Exhibits.
Exhibit
Number
------
3.1 Articles of Incorporation (incorporated by reference to the
Company's Annual Report on Form 10-K dated June 24, 1998).
3.2 Bylaws adopted December 5, 2002.
10.1 Stock Option Plan (incorporated by reference to the Amendment to
Schedule 14C Information Statement filed on August 13, 1997).
10.2 Bank Line of Credit (incorporated by reference to the Company's
Annual Report on Form 10-K dated June 24, 1998).
10.3 2004 Incentive Stock Option Plan (incorporated by reference to the
Proxy Statement pursuant to Schedule 14A filed on July 9, 2004).
14.1 Code of Business Conduct and Ethics (incorporated by reference to
the Company's Quarterly Report on Form 10-Q filed on November 15,
2004).
21 Subsidiaries of the Company (incorporated by reference to the
Company's Annual Report on Form 10-K dated June 24, 1998).
31.1 Certification by the President and Chief Executive Officer of the
Company pursuant to Rule 13a -- 14(a) of the Securities Exchange Act
of 1934.
31.2 Certification of the Chief Financial Officer of the Company pursuant
to Rule 13a - 14(a) of the Securities Exchange Act of 1934.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K.
Current report on Form 8-K filed on March 30, 2005, pursuant to Item
5.02, announcing a change in directors.
Current report on Form 8-K filed on January 14, 2005, pursuant to
Item 8.01, announcing a royalty purchase.
Current report on Form 8-K filed on October 27, 2004, pursuant to
Item 8.01, announcing a stock repurchase.
Current report on Form 8-K filed on August 4, 2004, pursuant to Item
8.01, announcing a royalty purchase.
41
Glossary of Terms
The following are abbreviations and definitions of terms commonly used in the
oil and gas industry and this Form 10-K.
Bbl. One barrel, or 42 U.S. gallons of liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet of natural gas equivalents.
Completion. The installation of permanent equipment for the production of
oil or gas.
Credit Facility. A line of credit provided by a group of banks, secured by
oil and gas properties.
DD&A. Refers to depreciation, depletion and amortization of the Company's
property and equipment.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in
sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new productive reservoir in a
field previously found to be productive of oil or natural gas in another
reservoir or to extend a known reservoir.
Extensions and discoveries. As to any period, the increases to proved
reserves from all sources other than the acquisition of proved properties
or revisions of previous estimates.
MBbls. One thousand barrels.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio
of 6 Mcf for each barrel of oil, which reflects the relative energy
content.
MMbtu. One million British thermal units. One British thermal unit is the
heat required to raise the temperature of a one-pound mass of water from
58.5 to 59.5 degrees Fahrenheit.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of natural gas equivalents.
Natural gas liquids. Liquid hydrocarbons that have been extracted from
natural gas, such as ethane, propane, butane and natural gasoline.
Net production. Oil and gas production that is owned by the Company, less
royalties and production due others.
NYMEX. New York Mercantile Exchange, the exchange on which commodities,
including crude oil and natural gas futures contracts, are traded.
Oil. Crude oil or condensate.
Operator. The individual or company responsible for the exploration,
development and production of an oil or gas well or lease.
42
Present value of proved reserves. The present value of estimated future
revenues to be generated from the production of proved reserves determined
in accordance with SEC guidelines, net of estimated production and future
development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to nonproperty related
expenses such as general and administrative expenses, debt service, future
income tax expense, or depreciation, depletion and amortization, and
discounted using an annual discount rate of 10%.
Proved developed nonproducing reserves. Reserves that consist of (i)
proved reserves from wells which have been completed and tested but are
not producing due to lack of market or minor completion problems which are
expected to be corrected and (ii) proved reserves currently behind the
pipe in existing wells and which are expected to be productive due to both
the well log characteristics and analogous production in the immediate
vicinity of the wells.
Proved developed producing reserves. Proved reserves that can be expected
to be recovered from currently producing zones under the continuation of
present operating methods.
Proved developed reserves. The combination of proved developed producing
and proved developed nonproducing reserves.
Proved reserves. The estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion.
Royalty. An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating
the wells on the leased acreage. Royalties may be either landowner's
royalties, which are reserved by the owner of the leased acreage at the
time the lease is granted, or overriding royalties, which are usually
reserved by an owner of the leasehold in connection with a transfer to a
subsequent owner.
SEC. The United States Securities and Exchange Commission.
Standardized measure of discounted future net cash flows. The after-tax
present value of proved reserves determined in accordance with SEC
guidelines.
Undeveloped acreage. Leased acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether such acreage contains
proved reserves.
Working interest. An interest in an oil and gas lease that gives the owner
of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of
drilling and production operations. The share of production to which a
working interest is entitled will be smaller than the share of costs that
the working interest owner is required to bear to the extent of any
royalty burden.
Workover. Operations on a producing well to restore or increase
production.
43
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Company has duly caused this report to be signed on
behalf of the undersigned thereunto duly authorized.
MEXCO ENERGY CORPORATION
Registrant
By: /s/ Nicholas C. Taylor
--------------------------------------------
Nicholas C. Taylor
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below as of June 29, 2005, by the following persons on
behalf of the Company and in the capacity indicated.
/s/ Nicholas C. Taylor
- --------------------------------------------
Nicholas C. Taylor
President, Chief Executive Officer
and Director
/s/ Donna Gail Yanko
- --------------------------------------------
Donna Gail Yanko
Vice President, Operations
and Director
/s/ Tamala L. McComic
- --------------------------------------------
Tamala L. McComic
Vice President, Treasurer
and Assistant Secretary
/s/ Thomas Graham, Jr.
- --------------------------------------------
Thomas Graham, Jr.
Chairman of the Board of Directors
/s/ Thomas R. Craddick
- --------------------------------------------
Thomas R. Craddick
Director
/s/ Jeffry A. Smith
- --------------------------------------------
Jeffry A. Smith
Director
/s/ Arden Grover
- --------------------------------------------
Arden Grover
Director
/s/ Jack D. Ladd
- --------------------------------------------
Jack D. Ladd
Director
44
INDEX TO EXHIBITS
Exhibit
Number Exhibit Page
------ ------- ----
3.1* Articles of Incorporation.
3.2*** Bylaws.
10.1** Stock Option Plan.
10.2* Bank Line of Credit.
10.3**** 2004 Incentive Stock Option.
14.1***** Code of Business Conduct and Ethics.
21* Subsidiaries of the Company.
31.1 Certification by the President and Chief Executive
Officer of the Company pursuant to Rule 13a -- 14(a) of
the Securities Exchange Act of 1934.
31.2 Certification of the Chief Financial Officer of the
Company pursuant to Rule 13a - 14(a) of the Securities
Exchange Act of 1934.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
- ---------
* Incorporated by reference to the Company's Annual Report on Form
10-K dated June 24, 1998.
** Incorporated by reference to the Amendment to Schedule 14C
Information Statement filed on August 13, 1998.
*** Filed with the Company's Annual Report on Form 10-K dated June 29,
2004.
**** Filed with the Company's Proxy Statement filed July 9, 2004.
***** Filed with the Company's Quarterly Report on Form 10-Q filed on
November 15, 2004.
45